Lived Climate Pollutants from APG-Flaring

MITIGATION

OF SHORT- PHASE 2: THE USE OF NEW LIVED CLIMATE METHODOLOGY TO REDUCE APG FLARING AT POLLUTANTS FROM REMOTE FIELDS

APG-FLARING REPORT

2021 Mitigation of Short-Lived Climate Pollutants from APG-Flaring

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Suggested Citation ACAP 2021, Mitigation of Short-Lived Climate Pollutants from APG-Flaring Project: Phase 2 - The Use of New Methodology to Reduce APG Flaring at Re- mote Fields. Arctic Contaminants Action Program (ACAP). 92 pp.

Author VYGON Consulting

Published by Arctic Council Secretariat

Cover photograph iStock / lanolan

Funding and support The Report was financed by the Arctic Council’s Project Support Instru- ment, which is managed by NEFCO. TABLE OF CONTENTS

TABLE OF CONTENTS ...... 1 DEFINITIONS AND ABBREVIATIONS ...... 2 INTRODUCTION ...... 12 EXECUTIVE SUMMARY ...... 13 RESULTS OF THE ANALYSIS OF TECHNOLOGICAL AND ECONOMIC EFFECT OF IMPLEMENTATION OF THE NOVOPORTOVSKOYE INVESTMENT PROJECT STAGE II ...... 15 ANALYSIS OF THE CURRENT REGULATORY SYSTEM TO ENCOURAGE THE REDUCTION OF SOOT AND METHANE EMISSIONS, INCLUDING EMISSIONS FROM APG FLARING ...... 25 ASSESSMENT OF APG REINJECTION TECHNOLOGY SCALING/COMMERCIALIZATION POTENTIAL IN THE RUSSIAN ARCTIC ZONE ...... 60 LIST OF COMPANIES FOR PROVIDING DECISIONS ON ADDITIONAL INVESTMENTS IN PROJECTS AIMED AT SOOT AND METHANE EMISSIONS REDUCTION ...... 73 DISSEMINATION OF RESULTS ...... 77 CONCLUSION ...... 78 APPENDIX A. CALCULATION OF ECONOMIC EFFICIENCY OF APG INJECTION ...... 79 APPENDIX B. DETAILS AND SUMMARY ON VARIOUS APG UTILIZATION TECHNOLOGIES ...... 81 APPENDIX C. COMPARISON OF APG UTILIZATION TECHNOLOGIES BY THEIR ENVIRONMENTAL AND ECONOMIC EFFICIENCY FOR THE NOVOPORTOVSKOYE FIELD ...... 85 APPENDIX D. MACROECONOMIC SCENARIO ...... 86 APPENDIX E. EMISSIONS FACTORS FOR APG UTILIZATION UNITS ...... 86 APPENDIX F. GEOPHYSICAL PROPERTIES OF TARGET ASSETS ...... 87 APPENDIX G. BASELINE EMISSIONS LEVEL ...... 88

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DEFINITIONS AND ABBREVIATIONS

Term used Definition ACAP Arctic Council’s Arctic Contaminants Action Programme

ACAP EG ACAP Expert Group

ACAP WG ACAP Working Group

Adsorbable organi- Adsorbable organically bound halogens, expressed as Cl, include cally bound halo- adsorbable organically bound chlorine, bromine and iodine. gens (AOX)

AEP Alberta Environment and Parks

AER Alberta Energy Regulator

AOGCC Alaska Oil and Gas Conservation Commission

APG Production Covers gas dissolved within the oil and the gas-cap gas (gas resid- ing above oil in a reservoir) producing through oil wells. This gas includes flared, vented and fugitive gases released in continuous and intermittent volumes from routine operations, emergency conditions, and the depressurisation of pipeline, compression and processing systems etc. As the APG comes out of solution it is usually separated before oil enters the pipeline.

The amount and composition of APG vary depending on the oil reservoir, extraction technology used, degree of depletion of the reservoir, and other factors. APG is typically mixed with ethane, butane and propane, other organic compounds, water, carbon dioxide, hydrogen sulphide, and other impurities, such as heavy metals (e.g. Hg, As). After extraction, the mixture is processed at a Gas Processing Plant (GPP), which separates out liquids and impurities and delivers pure, dry gas (methane) to a pipeline. The liquids or condensate can be sold, processed into liquid petroleum gas (e.g. used for cooking, heating, fuel), or further processed into more expensive petrochemical feedstocks.

Even reusing APG at the well site, e.g. for reinjection or power generation, usually requires processing to remove corrosive elements and create a uniform mixture, in addition to compression to a required pressure.

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Term used Definition Arctic Zone of the The Russian Arctic Zone is the territory as established by the Pres- Russian Federation idential Decree №287 dated 27 June 2017. (“Russian Arctic Zone)

Arsenic (As) Expressed as As, includes all inorganic and organic Arsenic compounds, dissolved or bound to particles.

Asset An “asset or operation,” is a logical business or operating unit (e.g., individual processing plants, gathering facilities, or offshore platforms; producing basins; regional assets; LNG operations). An operation/asset unit is to be defined such that all components of the unit are participating in the program (e.g., if several gas plants within a country are listed as one operation/asset, then a single emission survey should address all of the gas plants). The same operation/asset unit organisation shall be used for conducting the emission survey, the opportunity evaluation and describing results in the final report(s). For convenience, the term “assets” will be used to refer to “operations/assets” throughout this assign- ment

Associated Petro- Associated gas, also known as associated petroleum gas (abbrevi- leum Gas (APG) ated as APG) is gas that associated with the oil in a reservoir.

Associated Petro- All applications of using APG including delivery to gas processing leum Gas utilization plants/customers, power generation, gas reinjection and so on.

B Billion

Barrel of Oil Equiva- A barrel of oil equivalent (BOE) is the amount of energy that is lent (BOE) equivalent to the amount of energy found in a barrel of crude oil

BAT-BEP Best Available Techniques and Best Environmental Practices

bbl Barrel of oil

bcm Billion cubic meters

BEIS The Department for Business, Energy and Industrial Strategy (UK)

Biochemical oxygen Amount of oxygen needed for the biochemical oxidation of the or- demand (BOD5) ganic matter to carbon dioxide in 5 days. BOD is an indicator for the mass concentration of biodegradable organic compounds.

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Term used Definition Black Carbon (BC) A form of air pollution produced from incomplete combustion of fossil fuels, burning of biomass and cooking with solid fuels. Black carbon consists of pure carbon in several linked forms

BLM Bureau of Land Management (US)

bpd Barrels per day

CO2eq Carbon dioxide equivalent stands for a unit based on the global warming potential (GWP) of different greenhouse gases.

CAA Clean Air Act (US)

Cadmium (Cd) Expressed as Cd, includes all inorganic and organic Cadmium compounds, dissolved or bound to particles.

Chemical oxygen de- Amount of oxygen needed for the total oxidation of the organic mand (COD) matter to carbon dioxide. COD is an indicator for the mass concentration of organic compounds.

Chromium (Cr) Expressed as Cr, includes all inorganic and organic chromium compounds, dissolved or bound to particles.

cm Volume in cubic meter, m3

cm per t of… Volume in cubic meter per metric ton of…

CNG Compression of Dry Gas

CODAP Crude Oil Delivery and Acceptance Point

Combustion unit Unit burning refinery fuels alone or with other fuels for the production of energy at the refinery site, such as boilers (except CO boilers), furnaces, and gas turbines.

Continuous meas- Measurement using an 'automated measuring system' (AMS) or a urement 'continuous emission monitoring system’ (CEMS) permanently installed on site.

Copper (Cu) Expressed as Cu, includes all inorganic and organic Copper compounds, dissolved or bound to particles.

CPF Central Processing Facility

CPRA Canada Petroleum Resources Act

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Term used Definition Diffuse VOC emis- Non-channelled VOC emissions that are not released via specific sion emission points such as stacks. They can result from 'area' sources (e.g. tanks) or 'point' sources (e.g. pipe flanges).

EIA Environmental Impact Assessment

EPA The US Environmental Protection Agency

EU European Union

EU ETS EU Emissions Trading System

Existing unit/plant A unit/plant, which is not a new unit /plant.

FCC unit Fluid catalytic cracking (FCC): A conversion process for upgrading heavy hydrocarbons, using heat and a catalyst to break larger hydrocarbon molecules into lighter molecules.

Flaring High-temperature oxidation to burn combustible compounds of waste gases from industrial operations with an open flame. Flar- ing is primarily used for burning off flammable gas for safety reasons or during non-routine operational conditions.

Flue-gas The exhaust gas exiting a unit after an oxidation step, generally combustion (e.g. regenerator, Claus unit)

Fugitive VOC emis- Diffuse VOC emissions from 'point' sources. Fugitive emissions sions from leaks are unintentional losses and may arise due to normal wear and tear, improper or incomplete assembly of components, inadequate material specification, manufacturing defects, damage during installation or use, corrosion, fouling and environmental effects. Components also tend to have greater average emissions when subjected to frequent thermal cycling, vibrations or cryo- genic service.

Gas Processing Plant A gas processing facility (pre-treatment unit) that can remove liq- (GPP) uids from gas.

Gas to Oil Ratio The gas/oil ratio (GOR) is the ratio of the volume of gas that (GOR) comes out of solution, to the volume of oil at standard conditions

Gazprom groups Gazprom is a global energy company. Its main activities include geologic exploration, production, transportation, storage, refining and sale of gas, gas condensate and oil, sale of gas as motor fuel, as well as production and sale of heating energy and electricity.

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Term used Definition GCS Gas Compressor Station

Global Warming Po- GWP is a relative measure of how much heat a greenhouse gas tential (GWP) traps in the atmosphere. It compares the amount of heat trapped by a certain mass of the gas in question to the amount of heat trapped by a similar mass of carbon dioxide. GWP is expressed as a factor of carbon dioxide (whose GWP is standardized to 1).

GPA-32 (GCU) Gas Compressor Unit

Greenhouse Gas A GHG is a gas in an atmosphere that absorbs and emits radiation (GHG) within the thermal infrared range. This process is the fundamental cause of the greenhouse effect. The primary greenhouse gases in Earth's atmosphere are water vapour, carbon dioxide, methane, nitrous oxide, and ozone.

GTEPP Gas Turbine Electric Power Plant

GTL Gas-to-Liquids Conversion

H2S Hydrogen sulphide. Carbonyl sulphide and mercaptan are not included.

HFC (Hydrofluoro- HFCs are greenhouse gases (GHG) used in air conditioning, refrig- carbons) eration, solvents, foam blowing agents, aerosols and as fire re- tardant. Their use is growing as replacements for stratospheric ozone depleting substances (ODS), including chlorofluorocarbons (CFCs) and hydrochlorofluorocarbons (HCFCs) that are being phased out under the Montreal Protocol on Substances that De- plete the Ozone Layer.

Hydrogen chloride All gaseous chlorides expressed as HCl. expressed as HCl

Hydrogen fluoride All particulate and gaseous fluorides expressed as HF. expressed as HF

IFC International Finance Corporation

Indirect monitoring Estimation of the emissions concentration in the flue-gas of a pol- of emissions to air lutant obtained through an appropriate combination of measurements of surrogate parameters (such as O2 content, sulphur or nitrogen content in the feed/fuel), calculations and periodic stack measurements. The use of emission ratios based on S content in the fuel is one example of indirect monitoring. Another example

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Term used Definition of indirect monitoring is the use of Predictive Emissions Monitor- ing System (PEMS).

Intended Nationally (Intended) reductions in greenhouse gas emissions under the Determined Contri- United Nations Framework Convention on Climate Change (UN- bution (INDC) FCCC)

K Thousand

Lead (Pb) Expressed as Pb, includes all inorganic and organic lead compounds, dissolved or bound to particles.

LNG Liquefied Natural Gas

Lukoil LUKOIL is one of the largest oil & gas vertical integrated companies in the world accounting for over 2% of crude production and circa 1% of proved hydrocarbon reserves globally.

M Million

mbpd Million barrels per day

mcm Million cubic meters

Mercury (Hg) Expressed as Hg, includes all nascent (Hg (o), inorganic and organic mercury compounds, in vapour, dissolved or bound to particles.

MET Mineral Extraction Tax

Methane (CH4) Methane is a GHG and a volatile organic compound (VOC). It is produced through natural processes (i.e. the decomposition), but is also emitted from many man-made sources, including coal mines, natural gas and oil systems, and landfills.

MNRE Ministry of Natural Resources and the Environment of the Russian Federation

MPE Ministry of Petroleum and Energy of Norway

mtpa Million tons per annum

NAAQOs National Ambient Air Quality Objectives

NEFCO The Nordic Environment Finance Corporation

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Term used Definition New unit/plant A unit first permitted on the site of the installation or a complete replacement of a unit on the existing foundations of the installation

NGL Natural Gas Liquids

Nickel (Ni) Expressed as Ni, includes all inorganic and organic Nickel compounds, dissolved or bound to particles.

NMVOC VOC excluding methane.

Novatek PAO NOVATEK is the largest independent natural gas producer in Russia. The Company is principally engaged in the exploration, production, processing and marketing of natural gas and liquid hydrocarbons and have more than 20 years of operational experience in the Russian oil and natural gas sector.

NOx expressed as The sum of nitrogen oxide (NO) and nitrogen dioxide (NO2) ex- NO2 pressed as NO2.

NPD Norwegian Petroleum Directorate

NPV Net Present Value

OGA The UK Oil & Gas Authority

OGCF Oil and Gas Condensate field

Ozone (O3) Tropospheric ozone (O3) is the ozone present in the lowest por- tion of the atmosphere. It is responsible for a large part of the human enhancement of the global greenhouse effect. It is not directly emitted but is formed by oxidation of other ozone precur- sors, in particular methane (CH4) but also carbon monoxide (CO), non-methane volatile organic compounds (NMVOCs) and nitrogen oxides (NOx). Tropospheric ozone is a harmful pollutant that has detrimental impacts on human health and plants and is responsible for important reductions in crop yields.

PDO Plan for development and operation

Periodic measure- Determination of a measure and at specified time intervals using ment manual or automated reference methods.

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Term used Definition Predictive Emissions System to determine the emissions concentration of a pollutant monitoring system based on its relationship with a number of characteristic continu- (PEMS) ously monitored process parameters (e.g. fuel-gas consumption, air/fuel ratio) and fuel or feed quality data (e.g. the sulphur content) of an emission source.

PM2.5 A mixture of solid particles and liquid droplets found in the air with diameters generally of 2.5 micrometres and smaller.

Process off-gas The collected gas generated by a process which must be treated e.g. in an acid gas removal unit and a sulphur recovery unit (SRU)

PSI The Arctic Council Project Support Instrument (PSI) managed by NEFCO

RAZ Russian Arctic Zone

REA Russian Executing Agency for PSI Projects in the Russian Federa- tion

Recovery rate Percentage of NMVOC recovered from the streams conveyed into a vapour recovery unit (VRU).

Rosneft Rosneft is the leader of the Russian oil sector and the largest global public oil and gas corporation. Rosneft Oil Company is focused on exploration and appraisal of hydrocarbon fields, production of oil, gas and gas condensate, offshore field development projects, feedstock processing, sales of oil, gas and refined products in the territory of Russia and abroad.

RussNeft RussNeft among the top-10 Russian oil&gas companies by hydrocarbons production

Short Lived Climate SLCP include black carbon (BC), hydrofluorocarbons (HFC), me- Pollutant (SLCP) thane (CH4) and tropospheric ozone (O3).

SOx expressed as The sum of sulphur dioxide (SO2) and sulphur trioxide (SO3) ex- SO2 pressed as SO2.

SRU Sulphur recovery unit. Specific unit that generally consists of a Claus process for sulphur removal of hydrogen sulphide (H2S)- rich gas streams from amine treating units and sour water strip- pers. SRU is generally followed by a tail gas treatment unit (TGTU) for remaining H2S removal.

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Term used Definition Suspended particu- Finely divided solids or liquids that may be dispersed through the late matter (SPM) air from combustion processes, industrial activities or natural sources.

Tail gas Common name of the exhaust gas from an SRU (generally Claus process)

tcm Trillion cubic meters

Total inorganic ni- Total inorganic nitrogen, expressed as N, includes free ammonia trogen (Ninorg) and ammonium (NH4-N), nitrites (NO2-N) and nitrates (NO3-N).

Total nitrogen (TN) Total nitrogen, expressed as N, includes free ammonia and ammonium (NH4-N), nitrites (NO2-N), nitrates (NO3-N) and organic nitrogen compounds.

Total organic carbon Total organic carbon, expressed as C, includes all organic com- (TOC) pounds.

Total phosphorus Total phosphorus, expressed as P, includes all inorganic and or- (TP) ganic phosphorus compounds, dissolved or bound to particles.

Total suspended sol- Mass concentration of all suspended solids, measured via filtra- ids (TSS) tion through glass fibre filters and gravimetry.

Traditional Local TLK is to identify whether traditional and local Knowledge will lead Knowledge (TLK) to better project outcomes and If so, explains the plan to include TL K into a project; If not, explain why Traditional and Local Knowledge is not applicable or not feasible for this project.

TRRC Railroad Commission of Texas

UGSS Unified Gas Supply System. The UGSS is a unique engineering complex encompassing gas production, processing, transmission, storage and distribution facilities in European Russia and Western Siberia. The UGSS assures continuous gas supply from the well- head to the ultimate consumer.

Unit or plant A segment/subpart of the installation in which a specific processing operation is conducted.

VOC Volatile organic compounds “VOC” mean any organic compound, as well as the fraction of creosote, having at 293, 15 K a vapour pressure of 0.01 kPa or more, or having a corresponding volatility under the particular conditions of use.

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Term used Definition Volatile liquid hy- Petroleum derivatives with a Reid vapour pressure (RVP) of more drocarbon com- than 4 kPa, such as naphtha and aromatics. pounds

VTB Ecology VTB Ecology, a dedicated legal entity established in 2016, is responsible for VTB Bank’s environmental initiatives. Apart from environmental protection projects, the company is focused on stim- ulating green finance practices. With Russia's green finance market yet in its nascent stage, VTB Ecology has committed itself to developing such instruments and adapting them for the local context.

Zarubezhneft Zarubezhneft is a Russian oil & gas company of strategic im- portance acting for the state’s benefit, consistently developing and possessing a rich history and unique experience of foreign economic activity.

Zinc (Zn) Expressed as Zn, includes all inorganic and organic Zinc compounds, dissolved or bound to particles.

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INTRODUCTION

The Nordic Environment Finance Corporation Working Group and Expert Groups, (“NEFCO”) is an international financial institu- dealing with SLCPs); tion established by the five Nordic countries. NEFCO finances green projects that are in line • The Russian Government (primarily with the principles of sustainable development. the Ministry of Natural Resources and In addition to its own green investments, Environment, Ministry of Energy, NEFCO manages a number of Trust Funds Ministry of Economic Development, through which it facilitates the acceleration of other relevant Ministries); the green transition and provides financing to climate projects across the world. • Gazprom Neft, PJSC – Russian oil and Gas Company (“Gazprom Neft”), As part of its Trust Funds management, is implementing one of the largest up- NEFCO acts as the Fund Manager for the Pro- stream oil and gas projects in the Rus- ject Support Instrument (PSI) of the Arctic sian Arctic Zone (including the Novo- Council. In this capacity, NEFCO monitors the portovskoye and Messoyakha oil and implementation of the Arctic Contaminants Ac- gas condensate fields in the Yamalo- tion Program Working Group (ACAP WG) ap- Nenets Autonomous Region and the proved project: “Mitigation of Short Lived Cli- Prirazlomnoye oil field); mate Pollutants from APG flaring” (the “Pro- ject”). • VYGON Consulting LLC – an independent national energy sector advi- The purpose of the Project is to address SLCPs sor. The company’s main activity is (primarily Black Carbon, Methane and non-me- strategic consulting for business, ana- thane Volatile Organic Compounds) emissions lytical support for public authorities, associated with APG flaring that impact the energy sector research. Arctic Zone environment. The Project is implemented in several phases. Phase 1A “Evalua- The objective of Phase 2 consultancy work tion of Potential Impact of APG Flaring on the was to carry out an analysis of technological Arctic Zone Environment” was finalised on the and economic effect of implementation of the 20th November 2018; Phase 1B “Demonstration Novoportovskoye investment project Stage II, of best available technologies and practices as well as an analysis of the current regulatory (BAT-BEP) to reduce SLCP from APG-flar- system aimed at the reduction of soot and me- ing” was finalised on the 27th August 2019. thane emissions, including emissions from APG flaring. In addition, APG reinjection The PSI Committee, on the 28th March 2017, technology scaling/commercialization poten- approved the implementation of Phase 2 “The tial in the Russian Arctic Zone given the geo- use of new methodology to reduce APG flaring graphic and geological characteristics of the at remote fields”. assets and relevant environmental impacts in gas utilization program, partial injection and The Phase 2 of the Project key stakeholders: full-volume injection scenarios was assessed. As a result, the Consultant prepared a list of • The Arctic Council (including the companies for which it is advisable to scale up Arctic Contaminants Action Program the experience of the APG reinjection technology implemented by Gazprom Neft.

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EXECUTIVE SUMMARY

As part of the measures aimed at the rational use • Presence of a gas cap; of associated petroleum gas (APG), Gazprom Neft implements projects for the construction of • Close proximity of the oil-filled for- gas reinjection facilities, as well as power gen- mation to the gas cap; eration capacities. By the end of 2017, the construction of the first phase of the complex gas • Homogeneity of the formation struc- treatment plant (with the gas injection capacity ture. of 3.6 bcm per year) and the GTEPP (Gas Tur- bine Electric Power Plant with the installed ca- In addition, it is impractical to consider fields pacity of 96 MW) for electricity generation for with dominant gas production as areas of appli- own consumption was completed. Gazprom cation for APG reinjection technology, as well Neft finished the construction of the second as assets with a developed gas utilization infra- phase of the gas treatment plant by the end of structure, where additional investments for 2018. In particular, the company increased the APG utilization are not required. capacity of GTEPP to 144 MW, and the gas Thus, the list of target assets (existing fields, as reinjection capacity to 7.2 bcm. well as fields with the expected commissioning In order to implement the gas reinjection tech- before 2025) for scaling up the experience of nology, Gazprom Neft invested in the infra- the Novoportovskoye field in applying the tech- structure for the maintenance of reservoir pres- nology of maintaining the gas pressure by sure more than 46 B RUB (635 M EUR1) since reinjecting gas into the gas cap, is as follows: the beginning of the development of the Novo- • portovskoye field. In the time period under con- Severo-Komsomolskoe (SevKom- sideration (2019-2025), the reinjection technol- Neftegaz, JSC); ogy will generate incremental oil production in • Verkhnepurpeyskoye (RN-Purnefte- the amount of more than 9 Mt, which will pro- gaz, JSC); vide a positive economic effect. • The measures taken by Gazprom Neft in order Tagrinskoe (RussNeft, PJSC); to utilize APG are considered the best industry • Kholmistoye (Noyabrskneftegaz, practice in the Russian Arctic Zone. Therefore, JSC); it is advisable to scale up the experience of the Novoportovskoye field and implement it at • Pyakyakhinskoye (LUKOIL – West- other northern assets. The possibility of appli- ern Siberia, JSC). cation of the APG reinjection technology is determined by certain geological conditions. The The current regulatory system in Russia implies following key criteria for the applicability of the the achievement of the target APG utilization technology can be distinguished: level of 95%. Therefore, when the companies

1 72.54 RUB/EUR exchange rate based on Central Bank of Russia information for 2019.

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devise the development plans for oil fields, they utilization capacities (after the start of commer- take into account the restrictions on the possi- cial development) flare APG in excess of 5%. bilities for APG utilization. At such fields, the gas reinjecting technology can be considered as It is established that the Russian system for reg- additional APG utilization capacity, which will ulating APG flaring is conceptually similar to allow to increase oil production without violat- the system of the province of Alberta (Canada), ing current legislation. This mainly applies to because both set industry-wide restrictions on the fields of Gazprom Neft, Rosneft, Zarubezh- flaring and set universal regulatory standards in neft, etc. the field of APG flaring for all market participants. This fact suggests that individual deci- In order to scale up the technologies, it is also sions and mechanisms can be transferred from appropriate to consider oil fields, for which the one system to another and implemented in it, decision on the commissioning of development without contradicting the general structure and has not been made yet, as well as the fields that principles of regulation. are not likely to be launched before 2025. One of the limiting factors for the companies that On the contrary, the introduction of elements concerns these fields is the administration sys- from the Norwegian, British, Texan or Alaskan tem introduced in Russia in 2009. According to regulatory systems that rely on flaring permits it, the companies are required to provide an issued on case-by-case basis may be considered APG utilization scheme as part of the oil field impractical since it would require a substantial development projects. As a result of this, Rus- restructuring of the existing Russian legislative sian companies have to develop plans for APG frameworks in the field of APG utilization and utilization at the front-end engineering and de- flaring. In addition, the regulatory system of Al- sign stage. For the oil and gas industry, the berta has shown its effectiveness since Can- length of the investment stage (from design to ada’s actual APG utilization rate is relatively the start of commercial development) amounts high: it amounts to about 93%, compared to to about 5 years. For fields that will be launched 86% in Russia (Table 9). after 2025, the decision on APG utilization may be taken already today. Therefore, in addition to A drawback of the current Russian regulatory five listed above it is also recommended to con- system is the lack of incentives for further re- sider the technology of APG reinjection for six duction in APG flaring after reaching the target fields, five of which belong to the Gazprom APG utilization rate of 95%. In this regard, group. Specific list of the fields is provided in based on the experience of Alberta, it can be Paragraph 4. supplemented by a mechanism for providing incentives for APG utilization projects that would A significant shortcoming of the current Rus- otherwise be economically ineffective (after a sian regulatory system is the lack of incentives thorough economic assessment carried out in for further reduction of APG flaring after the accordance with pre-established rules in order achievement of the 95% APG utilization target. to determine the economic efficiency of the pro- In addition, the regulations allow flaring of ject). The benefit may be provided in order to more than 5% of APG at new fields (for 3 years incentivize faster implementation of the utiliza- after the depletion exceeds 1%, or up to the mo- tion project, for example, for new fields. The ment when the depletion of 5% is achieved). As royalty exemption, applied in Alberta as an in- a result, companies during the preparation of centive measure, in the case of Russia can be replaced with a reduction in MET on oil.

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1. RESULTS OF THE ANALYSIS OF TECHNOLOGICAL AND ECONOMIC EFFECT OF IMPLEMENTATION OF THE NO- VOPORTOVSKOYE INVESTMENT PROJECT STAGE II

1.1. Information about the Novoportovskoye field

The Novoportovskoye oil and gas condensate field was the first hydrocarbon field discovered on the Yamal Peninsula (Yamalo-Nenets Autonomous Region). Major oil and gas reserves were proved to be present here as early as in 1964, but the absence of transport infrastructure, coupled with the complex underlying geology, remained insurmountable obstacles to the full-scale development of the Novopor- tovskoye field.

Figure 1 – Novoportovskoye field and Russian Arctic Zone on the map of the Russian Federation

Novoportovskoye

Russian Arctic Zone Other Russian regions

Source: VYGON Consulting

While 117 exploratory wells had been drilled by A long period of preparation for the develop- 1987, proactive development of this asset did ment of the Novoportovskoye field is caused by not begin until after 2010, when Gazprom made a number of difficulties – low-permeability res- the decision to transfer it to its subsidiary Gaz- ervoirs, a significant gas cap and other geologi- prom Neft. cal properties (numerous rock destruction formed by tectonic activity) abnormalities leading to significant fragmentation of deposits.

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Commercial development was started by Gaz- 144 MW and gas reinjection capacities to 7.2 prom Neft in 2014. The Novoportovskoye field bcm. is one of the largest fields in the Russian Arctic Zone. Currently, oil production volumes exceed In 2020 the production of the Novoportovskoye 7 Mtpa, and its peak oil production is expected field is expected to amount to 8.8 bcm of APG, to be around 8 Mtpa. The viable production of of which 8.5 bcm (more than 95%) will be di- high-quality, low-sulphur oil on the Yamal Pen- rected for efficient utilization, including gas insula has been achieved through the use of cut- reinjection. ting-edge technologies, including the construction of horizontal and multilateral wells, and the The product of oil extraction is a multiphase use of multistage fracking. For the period up to mixture consisting of oil, produced water, APG, 2025, oil production is expected to be main- as well as mechanical impurities. For techno- tained at the level of 8 Mtpa due to the involve- logical preparation, this mixture via an infield ment of undeveloped reserves in the develop- pipeline is delivered to the central production ment. facility (CPF) (Figure 2). Within the existing preparation scheme of CPF, the multiphase The Novoportovskoye field has high gas to oil mixture is separated from mechanical impuri- ratio (GOR) which amounts to 700-1100 cm of ties and divided into components: gas per t of oil. In 2019 the Novoportovskoye field produced 8.6 bcm of APG. APG produc- . Liquid phase is sent to the further tion in the coming years is expected to amount stages of preparation at the CPF, after to 10 bcm, while total production volumes in which oil is transmitted for storage to 2020-2025 will exceed 56 bcm. the crude oil delivery and acceptance point (CODAP), from where crude of- As part of the measures for efficient utilization floading to tankers is undertaken from of APG, the company implements projects for the Arctic Gates terminal. the construction of gas reinjection facilities, as well as power generation capacities. . Gas phase or the produced APG is sent for processing to the GPP. After By the end of 2017, the construction of the first that, gas is partially supplied to the phase of the complex gas treatment plant (with GTEPP, and the main volume is sent the gas injection capacity of 3.6 bcm per year) for compression and subsequent and the GTEPP (with the installed capacity of reinjection. In this case, the technol- 96 MW) for electricity generation for own con- ogy of gas reinjection into the gas cap sumption was completed. is implemented in order to maintain reservoir pressure and, as a result, in- By the end of 2018 Gazprom Neft finished the crease oil recovery (detailed descrip- construction of the second stage of the complex tion of the technology is given in Sec- gas treatment plant. Most notably, the Company tion 3). increased GTEPP capacity to projected level of

16 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

Figure 2 – Scheme of the existing system for oil and gas preparation at the Novoportovskoye field

Ключевой элемент Pipeline Arctic terminal Key element of APG commissioning инфраструктуры station utilizationутилизации infrastructure ПНГ

Production Central Complex gas w ell stock production treatment plant facility

GTEPP Injection 12 Gas injection w ells 144 MW layers (2x multi-w ell pads) (3 stages x 48 MW)

Oil-gathering pipe Dry gas pipe Technological pipe Pressure pipe Injection pipe

Source: Gazprom Neft, VYGON Consulting

To increase the efficiency of APG utilization af- build a high pressure gas pipeline with the pos- ter 2021, it is planned to modernize the complex sibility of supplying gas to the unified gas sup- gas treatment plant with the possibility of ob- ply system (UGSS), located in Yamburg on the taining marketable products from APG, includ- other side of the Gulf of Ob, at a distance of ing dry gas, natural gas liquids (NGL) and sta- about 100 km. The implementation of this pro- ble gas condensate (SGC). ject will allow not only to market APG after 2021, but also prevent the possibility of gas The main part of dry gas, which contains pri- break-through in oil wells. The main factors in- marily methane, will be reinjected into the gas fluencing the probability of breakthroughs are cap for the purpose of maintaining reservoir the structure of oil and gas reservoirs, the pres- pressure, and will also be sent to generate elec- ence of fracturing, reservoir pressure and the tricity at GTEPP. mode of development.

In addition, in order to diversify the associated The actual and forecasted volumes of APG pro- gas utilization system, the company plans to duction and utilization are shown in Figure 3.

17 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

Figure 3 – APG utilization at the Novoportovskoye field by application in 2020-2025

4% In 2020-2025 injection technology application will lead to increase in oil production of approximately 7 Mt 36%

56 bcm Injection (Stages 1,2) 59% Other directions of efficient utilization, incl. gas monetization Technological utilization via soot-free flare tips*

* Within 5% permissible levels

Source: Gazprom Neft, VYGON Consulting

1.2. The economic effect of the application of APG reinjection technology in a gas cap

As part of the application of formation pressure production in the amount of approximately maintenance technology APG is used as an in- 7 Mt. jection agent (after 2021 – dry gas). The increase in oil production occurs due to an in- To implement gas reinjection technology, Gaz- crease in pressure in oil reservoir, and, as a re- prom Neft has invested in formation pressure sult, an increase in the production rate of pro- maintenance system more than 46 B RUB (635 duction wells. M EUR) since the beginning of field development (Table 1). In the considered time period (2020-2025), the injection technology will bring additional oil

18 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

Table 1 – Costs of APG reinjection technology at the Novoportovskoye field

Costs, B Time pe- Phase Steps RUB / M riod EUR

Gas-compressor station (GCS) with gas processing plant for injection of 3.6 bcm per annum

2014-2017 Gas-compressor unit GPA-32 «Ladoga» (production of REP-Holding with General Electric compressors).

Total capacity 128 MW (4X32 MW) Phase 1, 2 46 / 635 Expansion of the GCS capacity with gas processing plant for injection of 3.6 bcm per annum

2018 Gas-compressor unit GPA-32 «Ladoga» (production of REP-Holding with General Electric compressors).

Total capacity 128 MW (4X32 MW)

Source: Gazprom Neft

Considering the macroeconomic assumptions used in the evaluation (Table 19), revenue from the sale of additionally produced oil until 2025 will amount to 24 K RUB per t2 (Appendix D). Due to the lack of necessity for additional investment in production, as well as operating costs, taxes will form the main part of the cost structure (Appendix A).

2 Appraisal by VYGON Consulting

19 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

Figure 4 – Specific economic indicators of the employment of APG reinjection as enhanced oil recovery method, K RUB / t incr. oil

Source: VYGON Consulting (Evaluation and macroeconomic assumptions)

The sensitivity analysis for evaluating the gas injection technology is made relative to the following indicators and parameters: CAPEX, Oil price, Oil extraction effect (Figure 5). The conducted analysis allowed to reveal the maximum sensitivity to the oil price.

20 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

Figure 5 – Assessment of NPV sensitivity to 3 main factors variations

-4 -3 -2 -1 0 1 2 3 4 K RUB / t

Oil price -20% -10% -5% +5% +10% +20%

Oil production effect -20% -10% -5% +5%+10% +20%

CAPEX +20% +10% +5% -5% -10% -20%

EUR / t -50 -40 -30 -20 -10 0 10 20 30 40 50 60 Base NPV

Source: VYGON Consulting (Evaluation and macroeconomic assumptions)

1.3. Comparison of the Novoportovskoye field’s APG utilization technology to existing BAT-BEP

Environmental and economic indicators of injection technologies used at the Novoportovskoye field were compared with the best available technologies and best industry practices for the utilization of APG, which were studied and described in detail in the framework of Phase 1B of the Project (presented in Appendix B).

From the point of view of the abatement effect, all the main BAT-BEPs in the field of the prepared APG utilization were considered relative to venting and/or flaring:

• Injecting dry gas (Injection);

• Dry gas supply via a pipeline (Gas marketing);

• Compression of dry gas (CNG, Compressed Natural Gas);

• Liquefaction of dry gas (LNG, Liquefied Natural Gas);

• Conversion (GTL) of dry gas into other hydrocarbon liquids (GTL);

• Conversion of dry gas into chemical products, such as Methanol and Ammonia (natural gas conversion);

• Combustion of dry gas in engines / turbines and generation of electricity (Power).

21 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

As part of the Project, the abatement effect from the injection technology at the Novoportovskoye field was clarified based on actual data, and the cost-effectiveness of associated gas utilization measures was 3 evaluated. A comparison of the total reduction in CO2 equivalent emissions and associated costs for the period up to 2025 is shown in Figure 6.

Figure 6 – Comparison of the environmental and economic efficiency of BAT- BEP at the Novoportovskoye field

Abatement cost, EUR/t CO2-eq. Abatement cost, K RUB/t CO2-eq. 14 1,0 12 0,8 10 Ammonia 8 LNG Methanol 0,6 6 0,4 4 0,2 2 0 CNG GTL Injection 0,0 -2 0,5 1,0 1,5 2,0 NG Pipeline 2,5 -0,2 -18 Abatement, mln t CO2-eq. -1,4 -20 -22 -1,6 Specified effect of injection technology Implementation at Novoportovskoye field

Source: VYGON Consulting, results of Phase 1B of the Project

In the graph above, the sizes of the rectangles technology provides the best indicators for re- reflect the economic efficiency assessment var- ducing pollutant emissions. The improvement iability (vertical) and the emission reductions in economic indicators is mainly due to the ge- volume variability (horizontal) of the individual ological features of the Novoportovskoye field, technology obtained as a result of the Phase 1B as well as the operational efficiency of the Gaz- analysis. The orange rhombus corresponds to prom Neft implementing the project. the assessment of the specified effect of the injection technology application in Phase 2. The total effect of the implementation of BAT- BEP at the Novoportovskoye field (Figure 6) In general, the results of the evaluation of the amounts to 2.5 Mt of CO2-eq, which is compa- effectiveness of the injection correspond to the rable to the reduction of CO2-eq emissions in estimates obtained in the framework of Phase 1B. For the Novoportovskoye field, injection

3 Abatement costs were estimated as the sum of all cash flows associated with the implementation of the APG utilization project

22 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

the Russian Arctic4 by about 5% in the coming The measures taken by Gazprom Neft in order years. At the same time, in addition to the tech- to utilize APG are considered the best industry nological effect, there is an improvement in the practice in the Russian Arctic Zone. Therefore, project’s economics due to the increase in oil it is advisable to scale up the experience of the production as a result of the formation pressure Novoportovskoye field and implement it at maintenance. other northern assets.

1.4. Sources of information

• Products prices: • Amount of SLCP emissions in the Russian Arctic Zone: data on the vol- • Gas prices are calculated in accord- umes of APG production, utilization ance with Russian Government De- and flaring in the RAZ, as well as the cree (29.12.2000 № 1021, ed. corresponding volumes of SLCP 21.02.2019) “On State Regulations for emissions are presented in the Final Gas Prices and Transmission Service Report for Phase 1A of the Project Tariffs in the Russian Federation”, available at: http://www.consult- • Technical and economic parameters of ant.ru/docu- BAT-BEP: the parameters are pre- ment/cons_doc_LAW_29748/92d969 sented in the Final Report for Phase e26a4326c5d02fa79b8f9cf4994ee563 1B of the Project 3b/; • Payment rates for negative environ- • Oil products prices calculated with mental impact: the methodology of netback method using data from calculations is described by Russian Thomson Reuters CIS Commodities Government Decree (03.03.2017 № Insight app 255), available at http://www.consultant.ru/docu- • Chemicals products prices gathered ment/cons_doc_LAW_213744/92d96 from Thomson Reuters Kortes app, 9e26a4326c5d02fa79b8f9cf4994ee56 description available at 33b/ and “Measuring and collecting http://www.kortes.com/company/ negative environmental impact payments” Russian Government De- • APG reinjection volume and corre- cree(13.09.2016 № 913) “About base sponding incremental oil production: payment rates for negative environ- Gazprom Neft data mental impact and additional multipliers”, available at http://www.consult- • APG composition and production pro- ant.ru/docu- file, SLCP emissions volume: data up ment/cons_doc_LAW_204671/92d96 to 2025 acquired from Gazprom Neft 9e26a4326c5d02fa79b8f9cf4994ee56 and Ministry of Natural Resources 33b/ and Environment of the Russian Fed- eration • The sea and railway transportation:

4 Data on the volumes of APG production, utilization volumes of SLCP emissions are presented in the Final and flaring in the RAZ, as well as the corresponding Report on Phase 1A of the Project

23 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

• sea freights calculated with • Labor costs: data on regional labor https://www.searates.com/ru/ costs obtained from the Russian Fed- eration Federal State Statistical ser- • railway tariffs calculated with vices http://www.gks.ru/ https://www.alta.ru/railonline/

24 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

2. ANALYSIS OF THE CURRENT REGULATORY SYSTEM TO ENCOURAGE THE REDUCTION OF SOOT AND ME- THANE EMISSIONS, INCLUDING EMISSIONS FROM APG FLARING

2.1. APG flaring regulations – Russia

Oil and gas production activities are regulated CLIMATE CHANGE POLICY through license agreements provided by the Ministry of Natural Resources and Environ- The Nationally Determined Contribution ment, as well as relevant regional authorities. In (NDC) of the Russian Federation is to limit the some regions, most notably in the Khanty- anthropogenic GHG emissions to 70-75% of Mansiysk and Yamalo-Nenets Autonomous the 1990 level by 20305. Regions, it is mandatory to include an APG utilization percentage in the licence agreement. Most probably Russia will achieve its NDC target, since it would not require a decrease in If essential license conditions are violated, the GHG emissions from current levels: in 1990 ag- right to use the subsoil can be withdrawn as gregate GHG emissions amounted to 3352 M t stated in Article 20 of the Federal Law “On of CO2-eq., while the most recent official statis- Subsoil”7. However, the term “essential license tics indicate that in 2017 Russia emitted 2156 conditions” lacks a clear definition, which 6 M t of CO2-eq. or 64% of the baseline level. means that no clear criteria for the application of this punitive measure are provided. Theoret- ically, this provision may be used as ground to APG FLARING POLICY revoke a license due to failure to fulfil APG utilization rates, but to date there have been no APG utilisation and flaring legislation is ap- such cases. It should be noted that such practice plied universally, i.e. all of the regulations de- is not unique to Russia. For example, Article 12 scribed below are applicable to every field or of the Canada Petroleum Resources Act states company, and no specific provisions are pro- that “an environmental or social problem of a vided with regard there to. erious nature” may cause prohibition of activities with no exact definition thereof8.

5 Intended Nationally Determined Contribution of the 7 Federal Law “On Subsoil” of 03.03.1995 N 27-FZ, Ar- Russian Federation. Available at the official website ticle 20 of the UNFCCC: https://www4.unfccc.int/sites/submissions/INDC/Published%20Documents/Rus- 8 Canada Petroleum Resources Act (R.S.C., 1985, c. 36 sia/1/Russian%20Submission%20INDC_eng_rev1.doc (2nd Supp.)), Article 12. Available at: https://laws- lois.justice.gc.ca/eng/acts/C-8.5/ 6 Federal State Statistics Service (2019) Aggregate emissions of greenhouse gases. Available at: https://gks.ru/storage/mediabank/kl-2.xlsx

25 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

Table 2 – Emission payment rates, RUB per t of pollutant

Pollutant Emission payment rate

2011 2012 2013 2014 2015 2016 2017 2018

BC / SPM* 303 321 344 363 380 35 37 37

Benzo(a)py- 949552 100840 108236 114619 120532 524749 547296 54729 rene 7 42 17 92 55 1 9 69

NO2 241 255 274 292 305 133 139 139

NO 162 171 185 196 207 90 94 94

H2S 1105 1191 1264 1356 1439 658 686 686

SO2 73 80 84 90 95 44 45 45

Methane 190 201 215 227 238 104 108 108

NMVOC (С2-С5) 19 20 21 23 24 104 108 108

NMVOC (С6-С10) 19 20 21 23 24 0.1 0.1 0.1

NMVOC(С12-С19) - - - - - 10.4 10.8 10.8

CO 2.6 2.8 3.2 3.5 4.9 1.5 1.6 1.6

Mercury (Hg) - - - - - 17493 18244 18244

* Starting from 2016 there is no individual emission payment rate for BC, BC is regarded as SPM

Source: VYGON Consulting

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Table 3 – Emission payment rates, EUR per t of pollutant

Pollutant Emission payment rate

2011 2012 2013 2014 2015 2016 2017 2018

BC / SPM* 7.4 8.0 8.1 7.1 5.6 0.5 0.6 0.5

Benzo(a)py- 232251 252401 255799 225563 177838 70686 83044 74004 rene

NO2 5.9 6.4 6.5 5.7 4.5 1.8 2.1 1.9

NO 4.0 4.3 4.4 3.9 3.1 1.2 1.4 1.3

H2S 27.0 29.8 29.9 26.7 21.2 20.3 10.0 9.2

SO2 1.8 2.0 2.0 1.8 1.4 1.3 0.7 0.6

Methane 4.6 5.0 5.1 4.5 3.5 1.4 1.6 1.5

NMVOC (С2-С5) 0.5 0.5 0.5 0.4 0.4 1.4 1.6 1.5

NMVOC (С6-С10) 0.5 0.5 0.5 0.4 0.4 0.0 0.0 0.0

NMVOC(С12-С19) - - - - - 0.2 0.2 0.2

CO 0.06 0.07 0.08 0.07 0.07 0.02 0.03 0.02

Mercury (Hg) - - - - - 236 277 247

* Starting from 2016 there is no individual emission payment rate for BC, BC is regarded as SPM

Source: VYGON Consulting

According to the Federal Law “On environmen- According to the Russian legislation, every tal protection”, emissions should be compen- company that emits pollutants must have draft sated by the entities that cause them9. Payment maximum permissible discharge standards is calculated as a product of basic rate10 (Table agreed with authorities. Due to the fact that not 2), special indexes and mass of a pollutant re- all companies had the opportunity to achieve leased within a year. the targets within the allocated time, temporar-

9 Federal Law “On Environmental Protection” of 10Russian Government Decree (13.09.2016 № 913) 10.01.2002 N 7-FZ, Article 16 “About base payment rates for negative environmental impact and additional multipliers”

27 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

ily approved emission limits were also estab- – special multiplier for Arctic offshore lished. For those emitters that exceed permissi- greenfield𝐴𝐴𝐴𝐴𝐴𝐴 s (equal to 0.25 in the period from ble discharge standards, a multiplier of 511 is 01.01.2020𝐾𝐾 to 31.12.2030; otherwise – 1). The applied to the base payment rate, and for the multiplier allows to reduce the emissions pay- emissions in excess of the temporarily approved ment for offshore greenfield projects; emission limits a multiplier of 25 is used. In general, temporarily approved emission limits – multiplier for specially protected area were supposed to be similar to the amount of (equal to 2 in case a field is located in a spe- 𝐾𝐾𝑆𝑆𝑆𝑆 pollutant emissions generated from flaring of cially protected area, in other cases – 1). The 5% of APG, however in practice these two val- multiplier increases the emission payment rate ues may differ significantly. for projects that emit pollutants in environmentally sensitive areas; In 2012 a 95% APG utilization target was intro- duced12 along with the additional multiplier of – additional multiplier (equal to 25 if I < 1; 1 4.5 applied to the payments for emissions in ex- if I ≥ 1; 120 in case no proper metering equip- 𝐾𝐾 cess of the temporarily approved emission ment is installed). This multiplier further dis- limits. In 2013 this multiplier was raised to courages above-limits flaring and incentivizes 1213, in 2014 – to 25, starting from January 1, the installation of proper metering equipment; 2020, it amounts to 10014. Therefore, the maximum multiplier that can be applied to above- – Expenses cover index (calculated for a limit flaring is equal to 2500 (100х25). Capital group of companies or for a subsoil user; the in- 𝐼𝐼 expenditure for APG utilization infrastructure, dex is equal to the ratio of APG utilization cap- including investments in gas pipelines, com- ital expenditures to emission payments (calcu- pressor stations, separation units, facilities pro- lated without )). The index incentivizes invest- ducing electricity and heat and for re-injection, ment in APG utilization infrastructure as it al- 𝐼𝐼 may be deducted15 in order to practically reduce lows to substantially reduce the emissions pay- the value of the multiplier to 1. ment. In particular, it potentially allows subsoil users to reduce the total above-limit flaring Above-limit emissions payments are calculated multiplier from 2500 to 100; in accordance with the following formula16: – ith pollutant emission base rate; = × × × ( × (1 𝑖𝑖 𝐻𝐻 th )) × × , where:𝑛𝑛 – value of i pollutant above-limit emission. 𝑃𝑃 𝐾𝐾𝐴𝐴𝐴𝐴 𝐾𝐾𝐴𝐴𝐴𝐴𝐴𝐴 ∑𝑖𝑖=1 𝐾𝐾𝑆𝑆𝑆𝑆 𝐾𝐾 − (1) 𝑖𝑖 𝐼𝐼 𝐻𝐻𝑖𝑖 𝑀𝑀𝑖𝑖 The𝑀𝑀 law allows not to apply the additional mul- – multiplier for above-limit emissions tiplier for the fields where cumulative production does not exceed 1% of estimated recovera- (equal𝐴𝐴𝐴𝐴 to 100 starting from 2020). The multi- plier𝐾𝐾 is applied to the base emission payment ble reserves, not to apply it for three years or up rate for above-limit emissions; to the moment when the aforementioned indicator achieves 5%, whichever occurs first17; as

11Russian Government Decree (28.08.1992 № 632) 14Ibid. “Environmental pollution, waste disposal and other negative impact payments calculating practices” 15 Ibid., Provisions, Article 8

12Russian Government Decree № 7, 08.01.2009 (re- 16Ibid. vised 08.01.2009) 17 Russian Government Decree № 1148, 08.11.2012 13Russian Government Decree № 1148, 08.11.2012 (revised 08.11.2012), Article 3 (revised 08.11.2012)

28 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

well as not to apply the K coefficient for fields • Capital expenditure for APG utiliza- where the annual volume of APG production is tion infrastructure, including invest- less than 5 mcm, or for which the share of non- ments in gas pipelines, compressor hydrocarbon components in the produced APG stations, separation units, facilities exceeds 50%18. producing electricity and heat and for re-injection, may be deducted in order It also allows a company to reach the 95% uti- to practically reduce the value of the lization target by aggregating production across coefficient that increases the emission all of a company’s fields. However, if the com- payments to 1; pany is not able to reach this rate through ag- gregation, fines are calculated for each field in- • Liberalization of APG pricing in Feb- dividually19. ruary 2008;

To summarize, the system of emission pay- • Amendments to the Federal Law “On ments assumes a significant increase in rates in Gas Supply in the Russian Federa- case of APG flaring in excess of the 5% limit tion”21 made in December 2012 pro- through the application of additional coeffi- vided priority access to free capacity cients, while the payments for flaring of up to in gas transportation infrastructure to 5% of produced APG are relatively low. Invest- stripped dry gas produced from APG; ment in utilization facilities is also incentivized through the infrastructure CAPEX deduction • Amendments to the Federal Law “On mechanism (see the description of in Formula Electricity” adopted in 2010 to facili- 1) that allows to significantly reduce the amount tate priority access to the Unified Na- 𝐼𝐼 of emission payments. Thus, the current system tional Electricity Grid for power pro- aims to encourage the achievement of the 95% duced from APG and its deriva- national utilization target, while there are nei- tives22. ther considerable penalties for the flaring of up to 5% of produced APG, nor significant incentives for those who overachieve the utilization MONITORING AND REPORTING target. Licensed operators are supervised by both the Ministry of Natural Resources and regional au- INCENTIVES FOR APG UTILIZATION thorities, and either of the two can initiate license withdrawal in case of non-compliance In addition to the punitive measures for above- with a condition stipulated in the license. How- limits flaring, Russian legislation provides for ever, to date neither regional authorities nor the the provision of economic incentives aimed at ministry have revoked any license due to exces- incentivizing the utilization of APG20. These in- sive APG flaring. According to regulations, the clude the following measures: equipment used to measure gas that is being

18 Ibid., Provisions, Article 6 and power generation, consumption of APG at the field and APG re-injection. 19 Ibid., Provisions, Articles 11-15 21 Federal Law “On Gas Supply in the Russian Federa- 20 In accordance with BAT reference documents ITS tion” №241-FZ 28 – 2017 “Oil production” and ITS 29-2017 “Natural gas production” the following methods of APG utiliza- 22 Federal Law No 35-FZ “On the Electric Power Indus- tion are considered as Best Available Technologies: try” dated 26 March 2003 supply to GPPs for further transformation, supply to the Gas Transportation System, use of APG for heat

29 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

vented or flared must have the accuracy of approval certificates and be recorded with the ±5%23. All of the measuring equipment being State Register of Measuring Devices. used by operators must therefore have relevant

Table 4 – APG flaring regulatory system in the Russian Federation – Sum- mary

Issue Policy description

Climate change pol- NDC: reduce GHG emissions to 70-75% of the 1990 level by 2030. icy

Legislative re- O&G production activities are enabled through license agreements strictions on APG provided by the Ministry of Natural Resources and Environment, as flaring well as relevant regional authorities. In some regions it is mandatory to include the target APG utilization percentage in the licence agreement.

Companies are permitted to flare 5% of any APG they produce. Pro- ducers violating this limit are charged significant emission fees. Ex- emption is applicable to smaller oil and gas fields which produce fewer than 5 mcm of gas, where cumulative production is less than or up to 5% of recoverable reserves and where the share of non-hydrocarbon components in the produced APG exceeds 50%.

Penalties for flaring Companies are obliged to pay fines for flaring APG in excess of the and incentives for 5% limit. The system of fines is based on the application of multipli- APG utilization ers to the base emission payment rate. The maximum multiplier that can be applied in case of above-limit APG flaring is equal to 2500. License may be revoked in case of violations, however no such cases have been registered so far with regard to APG flaring.

Incentives include exemption of capital expenditure on utilization infrastructure from the emissions payment, priority access to GTS, priority access to the grid for electricity generated from APG.

Environmental Im- The list of facilities subject to mandatory EIA includes all large-scale pact Assessment energy facilities. The EIA is subject to public consultations. (EIA)

23 State All-Union standard “GOST 8.143-75. State sys- schedule for means of measuring volumetric flow of tem for ensuring the uniformity of measurements. gas within the range of 1*10-6 – 1*102 m3/sec.” State primary standard and all-union verification

30 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

Issue Policy description

Monitoring and re- Vented or flared gas should be measured with an accuracy of ±5%. porting All of the measuring equipment used by operators must have relevant approval certificates and be recorded with the State Register of Measuring Devices. The licensed operators are supervised by both the Ministry of Natural Resources and regional authorities.

Source: VYGON Consulting

2.2. APG flaring regulations – Norway

GHG emissions of the order of 80-95% from CLIMATE CHANGE POLICY the 1990 level by 2050.

Norway has set ambitious environmental goals both at the national level and within the frame- APG FLARING POLICY work of the UN Convention on Climate Change. The country’s original NDC submitted Since the beginning of oil production in Nor- in 2016 stated that it would achieve at least 40% way in the 1970s, the government’s policy pro- emission reduction by 2030 compared to the hibited gas flaring to avoid wasting valuable en- 1990 level24. However, in February 2020 the ergy. The pollution aspect of flaring and vent- NDC was updated and enhanced: the target re- ing was introduced later. The Norwegian envi- duction level was increased to at least 50% and ronmental policy historically has been based on towards 55%25. direct regulation of environmentally harmful emissions and discharges. Increasingly, eco- At the national level, the Climate Change Act nomic instruments such as taxes have been serves as the key regulatory document that sets used. greenhouse gas emissions reduction targets for 2030 and 205026. Currently, the 2030 target The Norwegian government does not set spe- mirrors the one set in the original NDC, how- cific gas flaring and venting targets, however ever it is likely to be adjusted in accordance flaring, other than the volumes necessary for with the 2020 update. The long-term target set safety reasons during normal operation, is not in the act is to transform Norway into a “low- permitted under the Petroleum Act without the emission society” by achieving reductions of approval of the Ministry of Petroleum and En- ergy (MPE)27. Approvals in the form of flaring

24 UNFCCC (2016) Norway’s Intended Nationally De- 26 Act relating to Norway’s climate targets (Climate termined Contribution. Available at: Change Act). Available at: https://lovdata.no/doku- https://www4.unfccc.int/sites/ndcstaging/Pub- ment/NLE/lov/2017-06-16-60 lishedDocuments/Norway%20First/Nor- wayINDC%20(Archived).pdf 27 Act of 29th of November 1996 No. 72 relating to petroleum activities, Article (§ 4-4). Available at: 25 UNFCCC (2020) Update of Norway's nationally de- https://www.npd.no/en/regulations/acts/act-29-no- termined contribution. Available at: vember-1996-no2.-72-relating-to-petroleum-activi- https://www4.unfccc.int/sites/ndcstaging/Pub- ties/#Section-4-4 lishedDocuments/Norway%20First/Norway_updated- NDC_2020%20(Updated%20submission).pdf

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permits are issued in a very restrictive manner, GHG emissions from most land-based industry which is evidenced by the fact the flaring and sectors, the oil and gas industry and aviation, venting in the country are virtually non-exist- and the price of emission allowances is cur- ent: according to the official statistics published rently equivalent to around 200 NOK (20.4 30 at Diskos portal, in 2019 only about 0.2 bcm of EUR ) per t of CO2eq. The oil and gas sector 28 31 APG was flared and vented . is also required to pay the Norwegian CO2 tax , the current tax rate amounts to about 500 NOK 32 Applications for annual offshore flaring permits (50.7 EUR) per t of CO2 . are evaluated directly by the Norwegian Petro- leum Directorate (NPD), and the permits are is- No direct incentives are provided for utiliza- sued by MPE. Permit applications must specify tion. However, it should be noted that Norway the type and level of atmospheric emissions and has substantial advantages in terms of its loca- the technology applied to avoid or reduce pol- tion in close proximity to major natural gas lution. Emission limits are set on a case-by-case markets, the well-developed pipeline infra- basis, with consideration of relevant and appli- structure and the fact that third-party access pol- cable national and regional standards. icy (i.e. the policy that implies that owners of pipelines are required to grant access to them to Moreover, operating companies are required to other companies) are in force. These factors have a solution for APG utilization before the make the marketing of APG substantially field development is initiated. Before an opera- easier. tor can develop a discovery, the Petroleum Act requires that a plan for development and operation (PDO) be approved by the MPE29. As part MONITORING AND REPORTING of the approval process, the operator must submit an EIA. The EIA describes any environ- Supervising environmental measures and activ- mental effects of expected emissions and dis- ities is an integral function of the NPD. The charges, including APG flaring and venting, NPD also monitors internal control systems for and includes a systematic review of costs and operators to ensure that the activities are benefits of any mitigating measures. The im- planned and implemented in accordance with pact assessment is subject to public consulta- the authorities’ requirements and the compa- tions. nies’ acceptance criteria goals.

Violation of the above regulations may trigger The NPD supervises the use of equipment that punitive measures, including a temporary sus- measures fuel consumption and the quantity of pension of activities. In addition to that, fiscal gas used for flaring and venting. Operators are and economic measures are also applied in the responsible for metering gas-to-fuel, flare, and form of the CO2 tax and the EU Emissions venting during the operational phase and are Trading System (EU ETS). The ETS covers obliged to establish an internal control system

28 Diskos portal (2020) Diskos Reports. Field Fuel, 31 Act of 21st of December 1990 №72 relating to tax flare and cold vent report. Available at: https://por- on discharge of CO2 in the petroleum activities on tal.diskos.cgg.com/prod-report-module/ the continental shelf

29 Act of 29th of November 1996 No. 72 relating to 32 Norwegian Ministry of Petroleum and Energy. En- petroleum activities, Article (§ 4-2). Available at: ergy Facts Norway. Taxes and Emissions Trading. https://www.npd.no/en/regulations/acts/act-29-no- Available at: https://energifaktanorge.no/en/et- vember-1996-no2.-72-relating-to-petroleum-activi- baerekraftig-og-sikkert-energisystem/avgifter-og- ties/#Section-4-2 kvoteplikt/

30 2019 average EUR/NOK exchange rate

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that ensures that the requirements of the regula- from the authorities. The operating company tions are met. These responsibilities include the has to operate within the flaring permit and re- obligation to check sensor calibration every six ports the amount of flared gas daily. The oper- months. ating company has to notify the authorities if it reaches the permit’s limits. For tax purposes, The amount of gas to the flare system is meas- the amount of gas to flare is reported every ured through a metering system with an accu- six months. racy of ±5%. This system is subject to audits

Table 5 – APG flaring regulatory system in Norway – Summary

Issue Policy description

Climate change policy NDC: reduce GHG emissions by 50-55% by 2030 compared to the 1990 level.

Climate Change Act targets: by 2030 – reduce GHG emissions by 40% compared to the 1990 level (will likely be updated in accordance with the current NDC); by 2050 – reduce GHG emissions by 80-95% compared to the 1990 level.

Legislative restrictions APG flaring, other than volumes necessary for safety reasons on APG flaring during normal operation, is not permitted without the approval of the MPE. Applications for annual offshore flaring permits are evaluated by the NPD, and the permits are issued by MPE. Per- mit applications must specify the type and level of atmospheric emissions and the technology applied to avoid or reduce pollution. Emission limits are set on a case-by-case basis (based on the evaluation of flaring permit applications), with consideration of relevant and applicable national and regional standards.

In addition, operating companies are required to have a solution for APG utilization before the field development is initiated: a plan for development and operation (PDO) must be approved by the MPE.

Penalties for flaring Punitive measures may be triggered in case of non-compliance, and incentives for APG including a temporary suspension of activities. In addition, eco-

utilization nomic measures are applied in the form of the CO2 tax and the EU ETS. No incentives are provided for APG utilization.

Environmental Impact As part of the PDO approval process, the operator must submit Assessment (EIA) an EIA. The EIA describes any environmental effects of expected

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Issue Policy description

emissions and discharges (including flaring and venting) and includes a systematic review of costs and benefits of any mitigating measures. The EIA is subject to public consultations.

Monitoring and report- NPD supervises environmental measures and activities, as well ing as the internal control systems for operators to ensure that the activities are planned and implemented in accordance with the authorities’ requirements and the companies’ acceptance criteria goals.

NPD also supervises the use of equipment that measures fuel consumption and the quantity of gas used for flaring and venting. The accuracy has to remain within the ±5% range.

Source: VYGON Consulting

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science, communications, coordination and in- 2.3. APG flaring regulations – ternational engagement activities. 33 Canada In November 2019, Canada released its Arctic and Northern Policy Framework. The international chapter of the Framework includes a CLIMATE CHANGE POLICY commitment to contribute towards accelerating and intensifying national and international re- Canada’s NDC submitted in 2016 stated that the ductions of GHG emissions and short-lived cli- country aimed to reduce its GHG emissions by mate pollutants.36 30% below 2005 levels by 203034. In 2017 the NDC was updated, the revised document high- lighted that in addition to addressing gases cov- APG FLARING POLICY ered under the UNFCCC, Canada was committed to take actions to reduce black carbon emis- Federal, provincial and territorial governments sions due to its contribution to Arctic warm- in Canada all have roles and responsibilities in ing35. the implementation of air quality management. Prior to publication in 2018 of ECCC’s Me- The Pan-Canadian Framework on Clean thane Regulations, gas flaring and venting in Growth and Climate Change is Canada’s plan Canada was generally a matter of provincial ju- to meet emissions reduction targets, grow the risdiction. Canada Petroleum Resources Act economy and build resilience to a changing cli- (CPRA) grants the federal government the right mate. The plan includes a pan-Canadian ap- to restrict or halt any operations in case of envi- proach to pricing carbon pollution, and ronmental problems37. measures to achieve reductions across all sectors of the economy. In 2018, Canada finalized national methane regulations that are expected to reduce methane To complement the Pan-Canadian Framework, emissions from the oil and gas sector by 40 to and to help guide Canada’s actions on reducing 45 percent by 2025 compared with 2012 levels. SLCPs, Environment and Climate Change Can- These regulations introduce venting emission ada (ECCC; a department of the federal govern- limits, and minimum operating and mainte- ment) released in 2017 a Strategy on Short- nance standards for the upstream oil and gas in- Lived Climate Pollutants. The SLCP Strategy dustry. They ensure that fugitive or venting outlines a holistic approach to reducing air pol- emissions of methane are reduced to prescribed lution and mitigating climate change by addressing SLCPs through enhanced mitigation,

33 Similar to the U.S. section, the section on Canada Available at: https://www4.unfccc.int/sites/ndcstag- does not provide a comprehensive summary of Ca- ing/PublishedDocuments/Canada%20First/Can- nadian APG-flaring and related regulations. These ada%20First%20NDC-Revised%20submis- are selected examples only. sion%202017-05-11.pdf

34 UNFCCC (2016) Canada’s INDC Submission to the 36 Canada, Arctic and Northern Policy Framework, In- UNFCCC. Available at: https://www4.un- ternational Chapter. Available at: fccc.int/sites/ndcstaging/PublishedDocuments/Can- https://www.rcaanc-cir- ada%20First/INDC%20-%20Canada%20-%20Eng- nac.gc.ca/eng/1562867415721/1562867459588 lish.pdf 37 Canada Petroleum Resources Act (R.S.C., 1985, c. 35 UNFCCC (2017) Canada’s 2017 Nationally Deter- 36 (2nd Supp.)). Available at: https://laws-lois.jus- mined Contribution Submission to the United Na- tice.gc.ca/eng/acts/C-8.5/ tions Framework Convention on Climate Change.

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limits at facilities where there is a higher poten- In order to illustrate the role of provinces in the tial to emit methane.38 regulation of APG utilization and flaring in Canada, the legislation of Alberta is reviewed The methane regulations are expected to reduce in greater detail in the following sections. Al- 20 million tonnes of methane in 2030. Can- berta was picked for further examination as the ada’s Federal methane regulations do not spe- leading province in terms of oil production vol- cifically target flared emissions. Only vented ume, in particular in 2019 Alberta produced 3.8 emissions are targeted, and flaring action is an mbpd of crude oil and equivalent, which ac- allowable compliance option under the regula- counted for 80.5% of the Canada’s total42. tions. Although gas conservation is preferred, gas flaring is less detrimental to the environment than allowing the gas to vent. Some prov- PROVINCE OF ALBERTA inces do not yet have sufficient infrastructure to conserve all produced gas. Local air quality objectives are set by individual provinces that might require emissions reduc- The federal government works with provincial tion beyond the level demanded by the governments to minimize regulatory duplica- CAAQS, and many Canadian provinces includ- tion where possible.39 ing Alberta, British Columbia and Saskatche- wan have independently implemented measures On the federal level, the function of regulators to reduce emissions from venting and flaring oil is to license pipeline and natural gas operations, and gas. as well as the collection of royalties. Canada Pe- troleum Resources Act (CPRA) grants the fed- . In the case of Alberta, air quality guidelines eral government the right to restrict or halt any are established under the Environmental Pro- operations in case of environmental problems40. tection and Enhancement Act (EPEA)43. They are set by Alberta Environment and Parks In addition, the Canadian Council of Ministers (AEP), a government body that regulates air of the Environment sets the Canadian Ambient emissions in the province, and specify parame- Air Quality Standards (CAAQS) for different ters such as maximum concentrations of partic- air pollutants, including fine particulate mat- ulate matter, sulphur dioxide (SO2), nitrogen di- 41 44 ter , of which black carbon is a component. oxide (NO2), carbon monoxide (CO), etc.

38 If a facility’s combined gas annual gas throughput https://www.ccme.ca/en/current_priori- (produced + received gas) exceeds 60,000 m3, it is ties/air/caaqs.html sub-ject to vent emission limits. 42 CER (2020) Estimated Production of Canadian 39 Environment and Climate Change Canada, “Cana- Crude Oil and Equivalent. Available at: dian Environmental Protection Act: Equivalency https://www.cer-rec.gc.ca/nrg/sttstc/crdlndptrl- agreements”. Available at: https://www.can- mprdct/stt/stmtdprdctn-eng.html ada.ca/en/environment-climate-change/services/canadian-environmental-protection-act-registry/agree- 43 Environmental Protection and Enhancement Act ments/equivalency.html (Alberta). Available at: http://www.qp.alberta.ca/documents/Acts/E12.pdf 40 Canada Petroleum Resources Act (R.S.C., 1985, c. 36 (2nd Supp.)). Available at: https://laws-lois.jus- 44 Alberta Ambient Air Quality Objectives and Guide- tice.gc.ca/eng/acts/C-8.5/ lines Summary. AEP, Air Policy, 2016, No. 2, pp. 2-6. Available at: https://open.alberta.ca/da- 41 Environment Canada (2010) National Ambient Air Quality Objectives. Available at:

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These standards are subsequently applied by the per month or 9 t of methane per month. Prior to Alberta Energy Regulator (AER) to set up- January 1, 2023, OVG volume must only con- stream petroleum industry gas flaring and vent- sider reported routine vent gas, whereas after ing targets. January 1, 2023, OVG volume must include all non-reported vent sources such as compressor The AER has the primary responsibility for reg- seals, pneumatic devices, and glycol dehydra- ulating the upstream petroleum industry in the tors. province and for conserving APG, and has con- solidated its requirements in Directive 060: Up- Defined vent gas (DVG) volume (vent gas from stream Petroleum Industry Flaring, Incinerating reported routine venting at all non bitumen fa- and Venting45. It provides regulatory require- cilities, excluding vent gas from pneumatic de- ments for flaring and venting in Alberta, as well vices, compressor seals, and glycol dehydra- as procedural information for flaring permit ap- tors) at a site with first receipt or production on plications and the measuring and reporting of or after January 1, 2022 must be limited to less flared and vented gas. than 3.0 thousand cubic meters of vent gas per month per site, or less than 1.8 t of methane per Directive 060 establishes the following APG month per site. Bitumen facilities are permitted 46 flaring reduction target for Alberta : to comply with a fleet-averaged venting limit of 1500 cubic meters per month, as a combined av- • The Alberta APG flaring limit is 670 erage from all bitumen facilities in the com- mcm per year (50% of the revised pany’s fleet. 1996 baseline of 1340 mcm per year); In addition to the above vent limits, equipment • If APG flaring exceeds the 670 mcm specific operating and maintenance standards limit in any year, the AER will im- have been put in place for pneumatic devices, pose reductions that will stipulate compressor seals, and glycol dehydrators. maximum APG flaring limits for individual operating sites based on analy- The above OVG, DVG, and equipment stand- sis of the most current annual data so ards apply, regardless of the outcome of any de- as to reduce flaring to less than 670 cision tree analysis discussions in the following mcm per year. section.

The AER does not consider venting an acceptable alternative to flaring. If venting is the only DIRECTIVE 060 REQUIREMENTS AND feasible alternative, the following limits ap- GUIDELINES ply47: As noted above, the Directive 060 provides reg- Overall vent gas (OVG) volume (all routine and ulatory requirements and guidelines for gas nonroutine vent gas) at a site must be limited to less than 15.0 thousand cubic meters of vent gas

taset/0d2ad470-117e-410f-ba4f-aa352cb02d4d/re- 46 Alberta Energy Regulator (2018) Directive 060: Up- source/97d1afdf-b66b-4805-be41- stream Petroleum Industry Flaring, Incinerating and a5a3f589c988/download/aaqo-summary-jun29- Venting, p. 11. Available at: https://www.aer.ca/docu- 2017.pdf ments/directives/Directive060_2020.pdf

45 Alberta Energy Regulator (2018) Directive 060: Up- 47 Ibid., p. 76 stream Petroleum Industry Flaring, Incinerating and Venting. Available at: https://www.aer.ca/documents/directives/Directive060_2020.pdf

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flaring and venting in Alberta, as well as proce- • Assess the opportunities to reduce dural information for flaring permit applica- flaring and venting in case the activity tions and the measuring and reporting of flared cannot be feasibly eliminated; and vented gas. The requirements are based on a framework that requires the operators of oil • Ensure that any flaring and venting is and gas production facilities to perform the fol- conducted in compliance with the per- lowing actions prior to flaring or venting formance requirements provided in APG48: the Directive 060.

• Evaluate the opportunities to elimi- This framework can be illustrated as the deci- nate flaring and venting; sion-tree based on the one provided in the Di- rective 06049 (Figure 7).

48 Alberta Energy Regulator (2018) Directive 060: Up- 49 Ibid., p. 12 stream Petroleum Industry Flaring, Incinerating and Venting, p. 44. Available at: https://www.aer.ca/documents/directives/Directive060_2020.pdf

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Figure 7 – Alberta APG flaring and venting decision tree

Source: AER, VYGON Consulting

Economic evaluation of APG utilization is cen- rate50.The procedure of economic evaluation of tral to this framework: companies are required APG utilization projects is as follows: to evaluate opportunities to utilize flared and vented gas, however the AER’s policy is that • Step 1. The economic efficiency of a gas must be utilized only if it is economically utilization project is evaluated on a viable to do so. royalties-in basis, i.e. with account for paying royalties for incremental gas The AER has specified economic evaluation and gas by-products that would other- procedures, assumptions, and parameters in the wise be flared or vented. If the NPV Directive 060. In particular, the document de- of the utilization project calculated in fines costs and gas prices that can be used in the that manner is greater than -55 000 evaluation, as well as the discount interest

50 Alberta Energy Regulator (2018) Directive 060: Up- https://www.aer.ca/documents/directives/Di- stream Petroleum Industry Flaring, Incinerating and rective060_2020.pdf Venting, pp. 16-18. Available at:

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CAD (-36 900 EUR51), the licen- for escalating consequences if timely remedial see/operator must implement the pro- actions are not taken or if repeat non-compli- ject. Thus, -55 000 CAD (-36 900 ance occurs. EUR) is seen as an “acceptable loss”. If the NPV is less than -55 000 CAD The enforcement actions include: (-36 900 EUR), the licensee/operator must proceed to Step 2 of the evalua- • Notice of Non-compliance: may be is- tion. sued when the AER identifies a non- compliance. It notifies a regulated • Step 2. The economic efficiency of party in writing that it is non-compli- the APG utilization project is evalu- ant with a specific regulatory require- ated on a royalties-out basis, i.e. as- ment, requests that it address the non- suming that no royalties are paid for compliance. It may be followed by an incremental gas and gas by-products investigation, which may lead to an that would otherwise be flared or enforcement response; vented. If the NPV calculated with account for that benefit amounts to - • Warning: may be issued at the end of 55 000 CAD (-36 900 EUR) or more, an investigation. It notifies a regulated the utilization project must be imple- party in writing that it has been found mented and the licensee/operator ob- to be in non-compliance with a spe- tains the right to apply for an “other- cific regulatory requirement; wise flared solution gas” royalty waiver52. If the NPV of the utiliza- • Orders: an order is issued according to tion project remains less than -55 000 statutorily prescribed factors and may CAD (-36 900 EUR) despite the pro- create a requirement to undertake spe- vision of the waiver, the licensee/op- cific time-bound actions or to stop erator may be allowed to flare and specific action; vent gas following an approval by the • Administrative Sanctions: “Adminis- AER. However, in that case it will trative sanctions” refers to a variety of have to follow the detailed perfor- tools and processes the AER can use mance requirements provided in the to ensure compliance. In particular, Directive 060. administrative sanctions may include the following: regulated party’s appli- PENALTIES AND SANCTIONS FOR VIO- cations may be subject to further discussion and analysis before approval; LATING THE LEGISLATION IN THE all of the regulated party’s applica- FIELD OF APG FLARING tions may be reviewed through a non- standard process; eligibility of the reg- The AER has established an “enforcement lad- ulated party to hold certain licences der system” to address non-compliance with may be restricted; existing authoriza- regulatory requirements. The enforcement lad- tions may be suspended or cancelled; der is based on appropriate responses to the se- riousness of the non-compliance and provides

51 2019 average CAD/EUR exchange rate https://www.aer.ca/documents/directives/Di- rective060_2020.pdf 52 Alberta Energy Regulator (2018) Directive 060: Up- stream Petroleum Industry Flaring, Incinerating and Venting, pp. 16-17. Available at:

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• Fees: for certain non-compliances un- • Prosecution: a court proceeding may der the energy resource enactments, be initiated against a regulated party, regulated parties may be issued a fee. individual, or corporation to have These are usually applied in case of committed an alleged offence under technical and minor violations, such an energy resource or specified enact- as late document submissions, and are ment; intended to address the costs and quality issues associated with missing data • Declaration of a Named Individual: a or data discrepancies that are not cor- statutory decision-maker may issue a rected before a filing deadline. A declaration naming persons in control schedule of fees is provided in the Oil of a regulated party that failed to com- and Gas Conservation Rules53. The ply with an AER order56. amount of fees is relatively insignificant. For example, a 500 CAD (335 EUR54) fee is prescribed for filing MONITORING AND REPORTING current month submissions after the filing deadline55; The AER inspects and audits wells and production facilities that it licenses, as well as responds • Administrative penalties: may be im- to public complaints related to petroleum indus- posed after an investigation where a try operations. The monitoring process ensures statutory decision-maker determines that operators with a non-compliant inspection that a regulated party has contravened history are inspected more frequently than op- a requirement, including circum- erators in good standing. stances in which a warning does not Requirements for measuring and reporting vol- adequately reflect the severity of the umes of gas flared, incinerated, and vented are non-compliance; an administrative provided in Directive 017: Measurement Re- sanction is not a sufficient response; quirements for Oil and Gas Operation and Di- or there are mitigating or aggravating rective 007: Volumetric and Infrastructure Re- circumstances that should be consid- quirements. In particular, the former states that ered; single point measurement uncertainty for gas flaring and venting should not exceed 5%57.

53 Government of Alberta (2020) Oil and Gas Conser- at: https://www.qp.alberta.ca/docu- vation Rules. Alberta Regulation 151/1971. With ments/Regs/1971_151.pdf amendments up to and including Alberta Regulation 40/2020. Part 17. Schedule of Fees. Available at: 56 AER (2019) Manual 013: Compliance and Enforce- https://www.qp.alberta.ca/document Program, pp. 12-15. Available at: ments/Regs/1971_151.pdf https://www.aer.ca/documents/manuals/Man- ual013.pdf 54 2019 average CAD/EUR exchange rate 57 AER (2018) Directive 017: Measurement Require- 55 Government of Alberta (2020) Oil and Gas Conser- ments for Oil and Gas Operation, p. 1 – 29. Available vation Rules. Alberta Regulation 151/1971. With at: https://www.aer.ca/documents/directives/Di- amendments up to and including Alberta Regulation rective017.pdf 40/2020. Part 17. Schedule of Fees, p. 113. Available

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Table 6 – APG flaring regulatory system in Canada (Alberta) – Summary

Issue Policy description

Climate change policy Canada’s NDC: reduce GHG emissions by 30% below 2005 levels by 2030.

Legislative restrictions Maximum total industry flaring volume is established for the on APG flaring province: current limit for Alberta is 670 mcm per year; if APG flaring exceeds the 670 mcm limit in any year, the AER will impose reductions that will stipulate maximum APG flaring limits for individual operating sites. Every proposed flaring project must be evaluated and, if economic, utilization is mandatory. If flaring goes ahead, economic viability must be reassessed annually.

Penalties for flaring The AER has established an “enforcement ladder system” to ad- and incentives for APG dress non-compliance with regulatory requirements. The en- utilization forcement ladder is based on appropriate responses to the seri- ousness of the non-compliance and provides for escalating consequences if timely remedial actions are not taken or if repeat non-compliance occurs. License revocation is one of the measures. If APG use is not economic, a royalty waiver can be applied for.

Environmental Impact EIA is only required for large projects. Any EIA is made public. Assessment (EIA)

Monitoring and report- The AER inspects and audits wells and production facilities that ing it licenses, as well as responds to public complaints related to petroleum industry operations.

Requirements for measuring and reporting volumes of gas flared, incinerated, and vented are provided in Directives 017 and 007. In particular, the former states that single point measurement uncertainty for gas flaring and venting should not exceed 5%.

Source: VYGON Consulting

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APG FLARING POLICY 2.4. APG flaring regulations – 61 United Kingdom Under the Energy Act 1976 (as amended by the Energy Act 201662) and the Petroleum Act 199863, the UK Oil & Gas Authority (OGA) is responsible for the regulation of the oil and gas CLIMATE CHANGE POLICY sector, including the issues related to APG flaring and venting. According to legislation, oper- National legislation and international commit- ators are required to have consents in place for ments are in place. On the national level, the the flaring and venting of APG; it is the function Climate Change Act 200858 states that net car- of the OGA to provide these consents64. bon account of the UK for all six Kyoto GHGs for the year 2050 must be at least 80% lower The objective of the OGA offshore flaring and than the 1990 baseline. venting regime is to eliminate any unnecessary or wasteful APG flaring and venting throughout In 2016 the NDC of the EU and its Member the lifecycle of a petroleum installation and rel- States was submitted. UK, together with other evant facilities65. The OGA recognizes that flar- European nations, committed to a binding tar- ing and venting of some amount of APG is un- get of an at least 40% domestic reduction in avoidable. However, in order to meet the objec- GHG emissions by 2030 compared to 199059. tive, the regulator requires that flaring and vent- However, due to the Brexit process the UK will ing should be kept to a technically and econom- have to develop its own NDC. It is expected that ically justified minimum66. the UK will be “bringing forward its own, increased NDC well ahead of COP26 (2020 Thus, consents that specify the volume of flar- United Nations Climate Change Conference ing and venting that must not be exceeded over scheduled to take place in Glasgow, the UK in a specified time serve as a key regulatory instru- 60 2021)” . Thus, the upcoming NDC is likely to ment applied by OGA. These consents are be more ambitious. given mainly in the context of filed development plan approvals. It is also important to note

58 Climate Change Act 2008. Available at: 62 Energy Act 2016. Available at: http://www.legisla- http://www.legislation.gov.uk/ukpga/2008/27/con- tion.gov.uk/ukpga/2016/20/contents tents 63 Petroleum Act 1998. Available at: http://www.legis- 59 UNFCCC (2015) Intended Nationally Determined lation.gov.uk/ukpga/1998/17/contents Contribution of the EU and its Member States. Availa- ble at: https://www4.unfccc.int/sites/ndcstaging/Pub- 64 Energy Act 1976, Section 12. Available at: lishedDocuments/United%20King- http://www.legislation.gov.uk/ukpga/1976/76/con- dom%20of%20Great% 20Britain%20and%20North- tents ern%20Ireland%20First/LV-03-06-EU%20INDC.pdf 65 OGA (2018) Flaring and Venting: OGA policy posi- 60 UK Parliament (2020) Climate Change: Written tion, p. 2. Available at: https://www.ogauthor- question – 12820. Available at: https://www.parlia- ity.co.uk/media/5014/flaring-and-venting-policy-posi- ment.uk/business/publications/written-questions-an- tion-website.pdf swers-statements/written-question/Commons/2020- 02-05/12820 66 OGA (2020) OGA’s Flaring and Venting Policy. Offi- cial website of the OGA. Available at: 61 Energy Act 1976. Available at: http://www.legisla- https://www.ogauthority.co.uk/licensing-con- tion.gov.uk/ukpga/1976/76/contents sents/consents/flaring-and-venting/

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that prior consents are not required for unantic- In case of non-compliance or breach of flaring ipated flaring that is necessary to avoid personal or venting consents, the OGA does not issue injury. fines but does impose increasingly severe penalties depending on the magnitude of the in- Applications for consents are reviewed on a fringement, in extreme cases this could lead to case-by-case basis with account for the tech- withdrawal of the licence70. nical and economic features of the field and potential for APG utilization, and operators are Although there are no incentives directly pro- given the opportunity to make representations vided for APG utilization, it should be noted about relevant technical and financial factors that certain reforms have improved the eco- before OGA determines whether to grant the nomic effectiveness of APG utilization pro- approval. jects. These include:

Where a field is flaring more than 40 t of APG • Restructuring and unbundling of the per day, which is a relatively small amount as it downstream gas market; translates to 5.2 to 19.2 mcm per year67, the flare level will be reviewed and a flare consent • Third-party access (TPA) to the up- issued annually. These applications will be sub- stream gas pipeline network; ject to detailed review by the Department for Business, Energy and Industrial Strategy • Wholesale and retail competition in (BEIS) and operators must exercise a high level downstream gas and electricity mar- of technical and operational diligence in esti- kets. mating quantities. This level of flaring is considered to represent a potential opportunity for It should also be noted that the UK, as is the further reduction in levels. These applications case with Norway, participates in the EU ETS, will need full supporting details with medium which means that operators are required to pur- and long term plans for flare reduction68. chase the emission allowances. However, due to the fact that Great Britain has left the EU, it By contrast, where a field is flaring less than 40 is currently expected that the country will re- t per day, a longer term flare consent may be main in the EU ETS only until January 1, 2021. applied for or issued. Less detailed information After that a national carbon tax will be intro- may be provided on the application form for duced as a substitute. It will impose a fixed rate 69 71 72 these flaring levels . of 16 £ per t of CO2-eq. (18.2 EUR ), which

67 The composition and, consequently, the density of 70 Oil & Gas UK. Atmospheric Emission – Flaring. Non APG varies widely depending on the type of field and Compliance. Oil & Gas UK Environmental Legislation the stage of production. The typical range is from Website. Available at: https://oilandgasukenviron- 763 to 2634 g/cm (see Filippov A. (2013) Composition mentallegislation.co.uk/contents/topic_files/off- of Associated Petroleum Gas. Available at: shore/flaring.html http://www.avfinfo.ru/engineering/e-06/) 71 Government of the United Kingdom (2020) Guid- 68 Oil & Gas UK. Atmospheric Emission – Flaring. Con- ance: Meeting climate change requirements from 1 sent Needed and How to Obtain It. Oil & Gas UK Envi- January 2021. Updated 5 November 2019. Available ronmental Legislation Website. Available at: at: https://www.gov.uk/government/publica- https://oilandgasukenvironmentallegisla- tions/meeting-climate-change-requirements-if- tion.co.uk/contents/topic_files/offshore/flaring.html theres-no-brexit-deal/meeting-climate-change-requirements-if-theres-no-brexit-deal 69 Ibid. 72 2019 average GBP/EUR exchange rate

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is similar to the current price of a EU ETS emis- weekly or monthly). It varies widely according sions allowance (20.4 EUR73). to stage of field production and between fields and operators74.

MONITORING AND REPORTING Requirements to metering is also in place: quan- tification of flaring should be conducted in line The OGA monitors compliance of operators with the provisions of the EU-ETS Phase II, with the rules and guidelines governing the oil which demand the accuracy of ±12.5%. These and gas industry. Field operators are required to requirements also state that metering equipment provide the OGA with detailed reports that con- should be located in a proper manner in order to tain information on production, APG flaring ensure accurate measurement and exclude non- volume, technical issues, etc. Frequency of re- reportable activities75. porting will be established through consent (e.g.

Table 7 – APG flaring regulatory system in the UK – Summary

Issue Policy description

Climate change policy Climate Change Act 2008: reduce GHG emissions by at least 80% by 2050 compared to the 1990 baseline. NDC of the EU and its Member States: reduce GHG emissions by at least 40% by 2030 compared to 1990. The UK is likely to develop its own increasingly ambitious NDC by 2021

Legislative restrictions APG flaring and venting consents are provided on a case-by-case on APG flaring basis, operators are given the opportunity to make representations about technical and financial factors before the regulator makes the decision. APG flaring without consent is allowed only for safety reasons. In addition, the UK will participate in the EU ETS until January 1, 2021. After that a national carbon tax will be introduced to substitute for the withdrawal from the EU ETS.

73 Norwegian Ministry of Petroleum and Energy. En- Legislation Website. Available at: https://oil- ergy Facts Norway. Taxes and Emissions Trading. andgasukenvironmentallegislation.co.uk/con- Available at: https://energifaktanorge.no/en/et- tents/topic_files/offshore/flaring.html baerekraftig-og-sikkert-energisystem/avgifter-og- kvoteplikt/ 75 Oil & Gas UK. EU GHG Emissions Trading Scheme/CRC Energy Efficiency Scheme. Sam- 74 Oil & Gas UK. Atmospheric Emission – Flaring. Re- pling/Monitoring Requirements. Oil & Gas UK Envi- porting Requirements. Oil & Gas UK Environmental ronmental Legislation Website. Available at: https://oilandgasukenvironmentallegisla- tion.co.uk/contents/topic_files/offshore/eu_ets.html

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Issue Policy description

Penalties for flaring The OGA does not issue fines, but it imposes punitive measures, and incentives for APG up to revoking a license. Although no incentives are provided for utilization APG utilization, gas market liberalization reforms have helped to improve the economic efficiency of APG utilization projects.

Environmental Impact An EIA is mandatory for all developments where the level of oil Assessment (EIA) production is intended to exceed 500 tpd (3 750 bpd).76

Monitoring and report- Field operators are required to provide the OGA with detailed ing reports that contain information on production, APG flaring volume, technical issues, etc. Frequency of reporting is established through consent (e.g. weekly or monthly) and may vary widely according to stage of field production and between fields and operators.

Requirements to metering are in line with the provisions of the EU-ETS Phase II, which demand the accuracy of ±12.5%.

Source: VYGON Consulting

Federal laws and regulations related to APG 2.5. APG flaring regulations – flaring and venting

United States Gas flaring and venting in the US is generally a matter of state jurisdiction. The federal role in regulating oil and natural gas production fo- CLIMATE CHANGE POLICY cuses primarily on environmental protection, including the issues of air quality. The US En- In its NDC submitted in 2016 the US made a vironmental Protection Agency (EPA) sets commitment to achieve the nation-wide target standards on air quality under the authority of of reducing its GHG emissions by 26-28% be- the Clean Air Act (CAA)78. These standards low its 2005 level by 2025 and to make best ef- (National Ambient Air Quality Standards, 77 forts to reduce its emissions by 28% . NAAQS) are established for six principal pollutants (including carbon monoxide (CO), lead

76 Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999. Available at: http://www.legislation.gov.uk/uksi/1999/360/contents/made

77 UNFCCC (2016) Intended Nationally Determined Contribution of the United States. Available at: https://www4.unfccc.int/sites/ndcstaging/PublishedDocuments/United%20States%20of%20Amer- ica%20First/U.S.A.%20First%20NDC%20Submission.pdf

78 Clean Air Act of 1963 (42 U.S.C. § 7401). Available at: https://www.govinfo.gov/content/pkg/STATUTE-77/pdf/STAT- UTE-77-Pg392.pdf

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(Pb), nitrogen dioxide (NO2), ozone (O3), parti- • Quad Oa (Standards of Performance cle pollution and sulphur dioxide (SO2)) in the for Crude Oil and Natural Gas Facili- form of specific emission limits, i.e. the units of ties for which Construction, Modifica- measure are parts per million or parts per billion tion or Reconstruction Commenced (ppm/ppb) by volume, and micrograms per cu- After September 18, 2015) regulates bic meter of air (µg/cm), while emissions limits sources of VOCs and GHGs that were in absolute values are not established79. The left unregulated under Subpart NAAQSs coexist with the commitment of the OOOO82. US to reduce GHG emissions by 26-28%, which means that both air quality targets and • Waste Prevention Rule (Waste Pre- emissions volume reduction goal within the vention, Production Subject to Royal- framework of the NDC have to be met. ties, and Resource Conservation. Final Rule) targets natural gas emissions as In most cases, the EPA allows states to develop a potential waste of public resources and implement the regulations necessary to and loss of royalty revenue. It prohib- meet federal standards. In addition, Bureau of its venting of natural gas, except un- Land Management (BLM) has the authority to der certain specified conditions, such regulate oil and natural gas production activities as in an emergency or when flaring is that occur on federal lands. technically infeasible. With respect to flaring, the rule requires operators to Federal laws related to oil and gas equipment reduce wasteful flaring of gas by cap- 80 and APG flaring include the following : turing for sale or using on the lease a percentage of their gas production. • Quad 0 (Standards of Performance for The required capture percentage in- Crude Oil and Natural Gas Produc- creases over time, and is also adjusted tion, Transmission and Distribution to provide for a base level of “allowa- for which Construction, Modification ble” flaring that ramps down over or Reconstruction Commenced After time. Specifically, starting from 2018, August 23, 2011, and on or before one year from the effective date of the September 18, 2015) focuses on rules final rule, operators must capture 85% regarding hydrocarbon emissions of their adjusted total volume of gas from onshore facilities such as storage produced each month. This percentage tanks, continuous bleed pneumatic increases to 90% in 2020, 95% in controllers, compressors, etc.81 2023, and 98% in 2026. Starting from

79 US EPA (2016) NAAQS Table. Available at: Transmission and Distribution for which Construc- https://www.epa.gov/criteria-air-pollutants/naaqs-tation, Modification or Reconstruction Commenced Af- ble ter August 23, 2011, and on or before September 18, 2015. Available at: https://www.ecfr.gov/cgi-bin/text- 80 US Department of Energy (2019) Natural Gas Flar- idx?node=sp40.7.60.oooo#_top ing and Venting: State and Federal Regulatory Over- view, Trends and Impact, pp. 15-16. Available at: 82 40 CFR Part 60, Subpart OOOOa — Standards of https://www.en- Performance for Crude Oil and Natural Gas Facilities ergy.gov/sites/prod/files/2019/08/f65/Natu- for which Construction, Modification or Reconstruc- ral%20Gas%20Flaring%20and%20Venting%20Re- tion Commenced After September 18, 2015. Availa- port.pdf ble at: https://www.law.cornell.edu/cfr/text/40/part- 60/subpart-OOOOa 81 40 CFR Part 60, Subpart OOOO—Standards of Per- formance for Crude Oil and Natural Gas Production,

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2018 operators were allowed to ex- venting activities. However, in many cases, the empt 0.15 mcm of gas per well per data is submitted voluntarily, and there are no month, this quantity declined to 0.1 uniform reporting requirements85. mcm in 2019, 0.05 mcm in 2020, and will be further reduced to 0.04 mcm in In order to illustrate the role of states in the reg- 2021, 0.03 mcm in 2022, 0.025 mcm ulation of APG utilization and flaring in the US, in 2024, and 0.02 mcm from 2025. the legislation of Texas is reviewed in greater The rule gives operators the option to detail in the following section. Texas was meet their capture targets on a lease- picked for further examination as the leading by-lease basis, or an average basis state in terms of crude oil production volume, over all of their Federal or Indian pro- in particular in 2019 Texas produced 5 mbpd, 86 duction from development oil wells which accounted for 41.4% of the US total . county-by-county or State-by-State83. For comparison, North Dakota that is the second largest oil producing state in the US ac- • EPA New Source Performance Stand- counted for only 11.5%. ards regulate VOC emissions from specific sources within the oil and nat- In addition, the regulations of Alaska in this ural gas industry which include new, field will be reviewed in order to illustrate the modified, and reconstructed natural policies of the only state that is partially located gas wells, centrifugal compressors, re- in the Arctic zone. ciprocating compressors, pneumatic controllers and storage vessels. This action also regulates VOC emissions TEXAS LAWS AND REGULATIONS RE- from leaking components at onshore LATED TO APG FLARING AND VENT- GPPs and provides standards for SO2 ING emissions from GPPs84. The regulation of APG flaring and venting is Individual states also have their own standards centered on the provision of flaring permits for controlling air quality, including APG flar- with the Railroad Commission of Texas ing regulations that may involve permitting and (TRRC) as the major authority. reporting requirements. These regulations vary considerably from state to state. A number of state agencies also collect data on flaring and

83 Bureau of Land Management (2016) Waste Preven- https://www.epa.gov/stationary-sources-air-pollution, Production Subject to Royalties, and Resource tion/crude-oil-and-natural-gas-production-transmis- Conservation. Final Rule. Section B. Summary of the sion-and-distribution Rule. 1. Venting and Flaring. Available at: https://www.federalregister.gov/docu- 85 US Department of Energy (2019) Natural Gas Flar- ments/2016/11/18/2016-27637/waste-prevention- ing and Venting: State and Federal Regulatory Over- production-subject-to-royalties-and-resource-conser- view, Trends and Impact, p. 16. Available at: vation https://www.energy.gov/sites/prod/files/2019/08/f65/Natu- 84 EPA (2016) Crude Oil and Natural Gas Production, ral%20Gas%20Flaring%20and%20Venting%20Re- Transmission and Distribution for Which Construc- port.pdf tion, Modification, or Reconstruction Commenced after August 23, 2011 and on or before September 18, 86 US EIA (2020) Petroleum & Other Liquids. Data on 2015: New Source Performance Standards (NSPS). US crude oil production. Available at: Rule Summary. Available at: https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_m bblpd_a.htm

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The TRCC Statewide Rule 3287 allows an oper- must include actual, metered volumes of gas re- ator to flare gas while drilling a well and for up ported by operators at the lease level88. to 10 days after a well’s completion. The majority of flaring permit requests the TRRC re- In case of non-compliance, such as APG flaring ceives are to permit flaring of casinghead gas without a permit, the TRCC has the authority to from oil wells. Other acceptable reasons for impose fines. If a violation is severe or re- flaring include processing plant shutdowns, peated, the regulator may resort to other puni- downstream repairs or maintenance, or existing tive measures, including suspension of activi- gas pipelines reaching their capacity. ties.

The TRRC issues flare permits administratively for 45 days at a time, for a maximum limit of ALASKA LAWS AND REGULATIONS RE- 180 days. Extensions beyond 180 days must be LATED TO APG FLARING AND VENT- granted through a Commission Final Order. If ING operators want to pursue an additional 45 days past the initial 45-day flare permit time period, Under the Alaska Oil and Gas Conservation Act they must provide documentation that progress waste of oil and natural gas is prohibited89. Ac- has been made toward establishing the neces- cording to the definition provided in the law, sary infrastructure to produce gas rather than “the release, burning, or escape into the open air flare it. of gas from a well producing oil or gas, except to the extent authorized by the commission (i.e. The most common reason for granting an exten- AOGCC – Alaska Oil and Gas Conservation sion to an initial flaring permit is when the op- Commission)” is considered waste90. For that erator is waiting for scheduled pipeline con- reason operators must report any instance of struction to be completed by a specified date. wasted oil or natural gas to the AOGCC along Other reasons for granting an extension include with a statement of compliance actions91. operators needing additional time for well clean-up and pending negotiations with land- Alaska Administrative Code also prohibits flar- owners. ing except in the case of emergency or system testing. This regulation stipulates operators Operators are required to report volumes of gas must report any release of gas to the AOGCC, flared on their monthly Production Report with a written supplement including volumes forms (Form PR) to the TRRC. The Form PR vented or flared for any incident that exceeds

87 Texas Administrative Code (TAC) Title 16. Economic hibited. Available at: https://law.jus- Regulation Part 1. Chapter 3. Article 3.32. Available tia.com/codes/alaska/2019/title-31/chapter-05/arti- at: https://www.rrc.state.tx.us/media/56528/chap- cle-2/section-31-05-095/ ter3-all-text-effective-march3-2020.pdf 90 Alaska Statutes (2019) Title 31. Oil and Gas. Chap- 88 Railroad Commission of Texas (2018) Flaring regu- ter 05. Alaska Oil and Gas Conservation Act. Article 3. lation. Available at: https://www.rrc.state.tx.us/about- General Provisions. Sec. 31.05.170. Definitions. Avail- us/resource-center/faqs/oil-gas-faqs/faq-flaring-reg- able at: https://law.justia.com/codes/alaska/2019/ti- ulation/ tle-31/chapter-05/article-3/section-31-05-170/

89 Alaska Statutes (2019) Title 31. Oil and Gas. Chap- 91 US Department of Energy (2019) Alaska Natural ter 05. Alaska Oil and Gas Conservation Act. Article 2. Gas Flaring and Venting Regulations, p. 2. Available Regulation of Operations. Sec. 31.05.095. Waste pro- at: https://www.energy.gov/sites/prod/files/2019/08/f66/Alaska.pdf

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one hour92. Additionally, operators must mini- venting is necessary for facility opera- mize the volume of gas released by utilizing tions, repairs, upgrades, or testing pro- good oil field engineering practices93. This reg- cedures is authorized at the AOGCC’s ulation provides clarification that any gas re- discretion; leased, burned, or permitted to escape into the air constitutes waste, except in the following • Upon application, the commission authorized situations94: will, in its discretion, authorize the flaring or venting of gas for purposes • Flaring or venting gas for a period not of testing a well before regular pro- exceeding one hour as the result of an duction. emergency or operational upset is authorized for safety; Fines may be imposed in case of non-compliance. In particular, entity may be liable for a • Flaring or venting gas for a period not civil penalty of not more than 100 000 USD for exceeding one hour as the result of a the initial violation and not more than 10 000 planned lease operation is authorized USD for each day thereafter on which the vio- for safety; lation continues95. In addition to that, AOGCC may impose a civil penalty for each 1 000 cubic • Flaring pilot or purge gas to test or feet (~28 m3) of natural gas flared, vented, or fuel the safety flare system is author- otherwise determined to be waste. The penalty ized for safety; shall be twice the fair market value of the natural gas at the point of waste96. • De minimis venting of gas incidental to normal oil field operations is au- If a violation is severe or repeated, the regulator thorized; may resort to other punitive measures, including suspension of activities. • Flaring or venting of gas for a period exceeding one hour if the flaring or

92 Alaska Administrative Code (2019) Section 20 AAC 94 Ibid., Subpart d 25.235 - Gas disposition, Subpart b. Available at: https://casetext.com/regulation/alaska-administra- 95 Alaska Statutes (2019) Title 31. Oil and Gas. Chap- tive-code/title-20-miscellaneous-boards-and-commis- ter 05. Alaska Oil and Gas Conservation Act. Article 3. sions/chapter-25-alaska-oil-and-gas-conservation- General Provisions. Sec. 31.05.150. Penalties, Sub- commission/article-3-production-practices/section- part a. Available at: https://law.jus- 20-aac-25235-gas-disposition tia.com/codes/alaska/2019/title-31/chapter-05/article-3/section-31-05-150/ 93 Ibid., Subpart c 96 Ibid., Subpart d

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Table 8 – APG flaring regulatory system in the US (Texas and Alaska) – Sum- mary

Issue Policy description

Texas Alaska

Climate change policy US NDC target: reduce GHG emissions by 26-28% below the 2005 level by 2025 and make best efforts to reduce the emissions by 28%.

Legislative restrictions Flaring permits serve as the main Flaring and venting are considered on APG flaring regulatory instrument. Legislation as waste of oil and natural gas, allows an operator to flare gas which is prohibited. For that rea- while drilling a well and for up to son, flaring and venting are al- 10 days after a well’s completion. lowed only for safety reasons, for The TRRC serves as the regulator testing or in case of emergency. and is responsible for the provision of permits. The majority of flaring permit requests received by the TRRC are to allow flaring of casinghead gas from oil wells. Other acceptable reasons for flaring include processing plant shutdowns, downstream repairs or maintenance, or existing gas pipelines reaching their capacity.

Penalties and sanc- In case of non-compliance, such as APG flaring without a permit, the reg- tions for violating the ulator has the authority to impose fines. If a violation is severe or re- legislation in the field peated, the regulator may resort to other punitive measures, including of APG flaring suspension of activities. No incentives are provided for APG utilization.

Environmental Impact The requirements to conduct, and the scope of, EIAs vary between activi- Assessment (EIA) ties conducted on private property, local, state or federally owned property, Native American tribal lands, and offshore production in the Gulf of Mexico. Drilling operations on private property (almost the entire Texas falls under that category) conducted under privately negotiated contracts are subject to the lowest level of EIA scrutiny, typically based on a finding in a statewide generic environmental impact statement (EIS) that oil and

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Issue Policy description

Texas Alaska

gas exploration, drilling and production activities do not constitute a generally adverse environmental impact activity97.

Monitoring and report- Operators are required to report Operators are required to regularly ing volumes of gas flared on their report their flaring and venting vol- monthly Production Report forms umes to the AOGCC. (Form PR) to the TRRC. The Form PR must include actual, metered volumes of gas reported by operators at the lease level.

Source: VYGON Consulting

97 M.P. Joy and S.D. Dimitroff (2016) Oil and gas regulation in the United States: overview. Thomson Reuters Practical Law. Available at: https://uk.practicallaw.thomsonreuters.com/9-525-1545?transitionType=Default&context- Data=(sc.Default)&firstPage=true&bhcp=1#co_anchor_a111966

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2.6. Comparative analysis of APG flaring regulations in countries under consideration

Thus, the regulatory environments for APG flaring and venting vary significantly across the countries under consideration. The major features thereof are summarized and compared in the following table.

Table 9 – Comparison of APG flaring regulatory systems of the reviewed countries

Comparison Russia Norway Canada (Alberta) United Kingdom US (Texas) US (Alaska) criteria

Climate Reduce GHG emis- 1st submission: Canada’s NDC: re- Reduce GHG emis- US NDC: reduce GHG emissions by 26-28% change policy sions to 70-75% of achieve >40% GHG duce GHG emissions by at least below the 2005 level by 2025 and make target – NDC the 1990 level by emission reduction sions by 30% below 40% by 2030 com- best efforts to reduce the emissions by 2030 by 2030 vs 2005 levels by 2030 pared to 1990 (EU 28% 1990;Current sub- NDC). The UK is mission: reduce likely to develop its GHG emissions by own NDC by 2021 50-55% by 2030 vs 1990

APG utilization Utilization: 84.4% Utilization: ~100% Utilization in Can- Utilization: 95.8% Utilization in the US: 90.9% in 2018 ada: 92.6% (< 0.2 bcm is flared)

Annual na- 95% target APG utili- No national target, Maximum APG flar- No national target, No national target, permits are required for tional flaring zation rate permits are re- ing volume for Al- permits are re- APG flaring target or limit quired for APG flar- berta – 670 mcm quired for APG flaring per year ing

Comparison Russia Norway Canada (Alberta) United Kingdom US (Texas) US (Alaska) criteria

Concept of Universal guidelines Flaring permits is- Universal guidelines Flaring permits is- Flaring permits is- Flaring and venting regulations for APG flaring sued on case-by- for APG flaring sued on case-by- sued on case-by- are allowed only for case basis case basis case basis safety reasons, for testing or in case of Allowed APG Flaring of up to 5% Flaring without a Flaring may be per- Flaring without a Flaring without a emergency flaring volume of produced APG is permit is prohibited mitted only if APG permit is prohibited permit is prohibited not considered ex- utilization is uneco- cessive nomic

Penalties for Emission payments Punitive measures Punitive measures The OGA does not In case of non-compliance, such as APG non-compli- serve as the main may be triggered in may be triggered in issue fines, but it flaring without a permit, the regulator has ance instrument. In case case of non-compli- case of non-compli- imposes punitive the authority to impose fines. If a violation of excessive flaring ance, incl. tempo- ance. License revo- measures, up to re- is severe or repeated, the regulator may re- special multipliers rary suspension of cation is one of the voking a license. UK sort to other punitive measures, including are applied (up to activities. Economic measures participates in the suspension of activities. x2500). License may measures include EU ETS, which may

be revoked the CO2 tax and the soon be replaced EU ETS with carbon tax

Incentives for Priority access of No direct benefits Royalty waiver may No direct benefits are provided for APG utilization APG utilization APG to the GTS, pri- are provided for be provided if APG ority access to the APG utilization utilization is uneco- grid for electricity nomic without it generated from APG, exemption of utilization infrastructure CAPEX

Comparison Russia Norway Canada (Alberta) United Kingdom US (Texas) US (Alaska) criteria

from emission payments

Source: Rosstat, World Bank, CER, OGA, VYGON Consulting

CLIMATE CHANGE POLICY TARGETS veloped upstream infrastructure and other factors that make the marketing of APG substan- Every country under consideration has made a tially easier. commitment under the United Nations Frame- work Convention on Climate Change in the form of a GHG emissions reduction target. The APG FLARING POLICIES targets themselves differ in terms of the baseline and target years, as well as ambitiousness. Generally speaking, the regulatory systems in In particular, Russia, the UK and Norway aim the field of APG flaring in the countries, states to cut GHG emissions by 2030 relative to the and provinces under consideration rely on one 1990 level by 25-30%, at least 40% and 50-55% of the two models: they either set an industry- respectively. It is also worth noting that among wide target and establish universal guidelines the reviewed countries Norway is the only for APG flaring, or prohibit APG flaring with- one that increased its target after the first sub- out a permit and issue those on a case-by- mission. case basis.

Russia with its 95% APG utilization target and APG UTILIZATION RATES Alberta with the annual industry-wide limit on APG flaring (maximum flaring volume is cur- According to the most recent national statistics rently set at 670 mcm per year) fall under the the rate of APG utilization in Russia amounted first category. The ways to ensure that these tar- to 84.4 % in 201898. Despite the fact that certain gets are met, however, differ significantly. The progress has already been achieved in this field Russian regulatory system provides for certain (in particular, in 2012 the utilization rate stood flexibility for the companies: regardless of any at 75.9%, by 2015 it increased to 87.6% and circumstances, every operator is allowed to since then has been floating within the 84-88% flare 5% of the produced APG without being range), the country still lags behind the devel- penalized with the application multipliers to the oped oil producing countries. emission payment. By contrast, the regulatory system in Alberta demands that APG may be Based on the World Bank data on flaring, APG flared only if utilization is economically unvia- utilization rates of all other countries under con- ble with account for the provision of a royalty sideration (Norway, Canada, the UK and the waiver: every utilization project is subject to US) was over 90%99. Norway, in particular, is thorough economic evaluation conducted in ac- frequently regarded as one of the best cases cordance with the methodology established by since flaring there is virtually non-existent, the regulator, all such projects must be imple- which results from the country’s zero-tolerance mented if deemed economically feasible. approach to the issue, long history of regulations (as noted above, the government’s policy The regulatory systems of Norway, the UK and prohibited gas flaring to avoid wasting valuable Texas are based on the other model and are con- energy since the beginning of oil production in ceptually quite similar to each other. All three the 1970s, i.e. even before the pollution aspect require the operators to apply for flaring per- of flaring and venting was recognized as a ma- mits, which serve as the key regulatory instru- jor environmental issue), as well as its well-de- ment. The permits are issued on a case-by-case basis with account for the specific technical and

98 Rosstat (2019) Technological development of in- 99 World Bank (2020) Global Gas Flaring Reduction dustries. Energy efficiency. Rate of utilization of asso- Partnership (GGFR) Available at: ciated petroleum gas. Available at: https://www.worldbank.org/en/programs/gasflar- https://www.gks.ru/folder/11189 ingreduction#7

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economic features of each individual site. Flar- Transportation System, as well as priority ac- ing without consent is prohibited with very few cess to the grid for electricity generated from exceptions mostly related to safety reasons (i.e. APG. In Canada, a royalty waiver may be pro- flaring in case of emergency). However, the vided in case APG utilization is uneconomic technicalities, such as the term for which per- without it. mits are provided, as well as the application review mechanism, vary across the three. As for Alaska, flaring and venting are permitted only 2.7. Suggestions for further im- for safety reasons, for testing or in case of provement of the Russian emergency. APG flaring regulatory sys- It should be noted that in addition to the mechanism described above Norway and the UK ap- tem based on the analysis ply economic instruments: both countries currently participate in the EU ETS (although the of the international experi- UK is expected to withdraw from the system by ence January 1, 2021 due to the Brexit, a fixed carbon tax will likely be introduced as a substitute Based on the analysis of the regulatory experi- after that), while the Norwegian petroleum in- ence of major oil producers among the member- dustry is also required to pay the CO2 tax. and observer-states of the Arctic Council the suggestions for further improvement of the Russian APG flaring regulatory system can be PENALTIES AND INCENTIVES provided. The countries, states and provinces under con- It has been established that the Russian APG sideration have access to quite similar sets of flaring regulatory system is conceptually simi- punitive measures that may be applied in case lar to that of Alberta, since both establish indus- of non-compliance. These include fines and try-wide limits on flaring and provide universal various administrative actions ranging from regulatory guidelines. This implies that individ- warnings and notices of non-compliance to sus- ual solutions and mechanisms can be trans- pensions of activities and license revocations ferred from one system to the other and imple- (with the exception of the UK’s OGA that relies mented therein without contradicting the over- solely on administrative measures). all structure and general principles. By contrast, the introduction of elements from the Norwe- As for the incentives, in the practice of Norway, gian, British, Texan or Alaskan systems would the UK, Texas and Alaska no benefits are pro- require substantial restructuring of the existing vided for APG utilization. In part, this may be Russian regulations, which can be considered attributed to their well-developed infrastructure impractical. and liberalized domestic energy markets, since the availability of these features make it easier A significant shortcoming of the current Rus- to utilize APG in a cost effective manner (e.g. sian regulatory system is the lack of incentives in the case of the UK, these features include for further reduction of APG flaring after the third-party access to the upstream gas pipeline achievement of the 95% APG utilization target. network and wholesale and retail competition in In addition, the regulations allow flaring of downstream gas and electricity markets). more than 5% of APG at new fields (for 3 years after the depletion exceeds 1%, or up to the mo- By contrast, Russia and the province of Alberta ment when the depletion of 5% is achieved). As provide incentives aimed at increasing the rate a result, companies during the preparation of of APG utilization. In the Russian Federation utilization capacities (after the start of commer- these include priority access of APG to the Gas cial development) flare APG in excess of 5%.

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In this regard, based on the experience of Al- in Russian oil refining is incentivized by the berta it could be supplemented by a mechanism provision of benefits. for the provision of benefits to APG utilization projects that are uneconomic without it (after a A similar measure is currently proposed for thorough economic assessment carried out in support of the petrochemical industry: the pos- accordance with pre-established rules in order sibility of introducing a reverse excise tax on to determine whether a project is economically LPG and ethane is being discussed. According viable or not). The benefit may be provided in to the proposal, a subsidy for LPG will be avail- order to incentivize faster implementation of able to companies that will launch petrochemi- the utilization project, for example, for new cal capacities after 2021 or agree to invest at fields. The royalty waiver applied in Alberta as least 65 bln rub. (896 M EUR102) in the devel- an incentive measures could be substituted with opment of the industry. As for the ethane sub- the reduction of MET on oil. sidy, companies can either fulfil the same investment criteria, or launch new petrochemical It is important to note that similar mechanisms processing capacities of at least 300 000 t of have previously been developed and applied in ethane per year from 2022. the Russian oil and gas industry. For example, one of the instruments aimed at supporting Rus- Another example is the introduction of invest- sian oil refining is the provision of a reverse ex- ment incentives for the Samotlor field in the cise tax on oil (a tax deduction). The value of form of an annual MET reduction. In particular, the negative excise tax depends on the structure Article 343.2 of the Russian Tax Code was sup- of the refinery’s product (its amount would be plemented with a clause on the MET tax deduc- more substantial for a modernized refinery with tion in the amount of 2.9 bln rub. per a tax pe- a high yield of light oil products), as well as on riod of one month. Thus, the annual tax deduc- the region where the refinery is located due to tion amounts to 35 bln rub. It will be applied for the presence of a logistic coefficient in the for- 10 years in the period from January 1, 2018 to mula for calculating the reverse excise tax100. December 31, 2027103.

Refineries are eligible for this deduction if they For its part, PJSC “Rosneft Oil Company”, the have received the “Certificate of an entity en- parent company of the field operator (JSC gaged in oil refining operations”. In turn, one of “Samotlorneftegas”), takes on substantial in- the options to obtain this certificate is to con- vestment obligations aimed at long-term include an agreement on modernization in the crease in production volumes, creation of new amount of at least 60 bln rub.101 Thus, the implementation of investments in modernization

100 Tax Code of the Russian Federation (Part Two) 102 72.54 RUB/EUR exchange rate based on Central dated 05.08.2000 №117-FZ (revised 18.03.2020), Arti- Bank of Russia information for 2019. cle 193, paragraph 8. Available at: http://www.consultant.ru/docu- 103 Tax Code of the Russian Federation (Part Two) ment/cons_doc_LAW_28165/22201a65e dated 05.08.2000 №117-FZ (revised 18.03.2020), Arti- 4f59a582714243c15b655989bd57066/ cle 343.2. Available at: http://www.consultant.ru/cons/cgi/online.cgi?req=doc&base= 101 Tax Code of the Russian Federation (Part Two) LAW&n=348019&fld= dated 05.08.2000 №117-FZ (revised 18.03.2020), Arti- 134&dst=16759,0&rnd=0.16998929470863722#0418 cle 179.7, paragraph 3. Available at: http://www.con- 36651967175564 sultant.ru/document/cons_doc_LAW_28165/77cab7d67 5033bc7a0791a85db10d0fef092775c/

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jobs, growth of the state revenue base, and de- volume of flaring does not exceed 5% of the velopment of regional infrastructure104. produced APG, as well as when the investments are made in the utilization infrastructure, as is While the introduction of additional fines or in- the case with the Novoportovskoye field. crease of emission payments may also be seen as an instrument to further discourage flaring, Secondly, additional fiscal pressure is likely to such measures are not recommended for two cause adverse effects such as reduction of oil main reasons. production volume. In particular, APG utilization may be uneconomic due to remoteness of Firstly, we believe that the current level of fines fields. Under such circumstances additional provided in the Russian regulatory system is fines would reduce the economic viability of the significant enough. The amount of environmen- project thus limiting the production potential. tal payments can be insignificant only when the

104 PJSC “Rosneft Oil Company” (2017) The Russian tives for the Samotlor field. Press release dated Octo- Ministry of Finance and Rosneft Oil Company have ber 6, 2017. Available at: https://www.ros- agreed on the estimated effect of investment incen- neft.ru/press/releases/item/188013/

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3. ASSESSMENT OF APG REINJECTION TECHNOLOGY SCALING/COMMERCIALIZATION POTENTIAL IN THE RUSSIAN ARCTIC ZONE

Analysis of the technical and economic effectiveness of APG utilization options has shown that the technology used at the Novoportovskoye field demonstrates the best performance in terms of emissions reduction among all existing BAT-BEPs. In this regard, it is advisable to scale up the experience of PJSC Gazprom Neft and use it at other Arctic assets.

Worth to mention that the Arctic zone of Russia is very different from traditional producing regions. Specifically, the Arctic is characterized with a number of geographical and climatic restrictions, as well as with features associated with low infrastructure development. In other words, technologies that are most effective for the Arctic zone and for Russia as a whole may vary.

3.1. Description of the technology. Key features and limitations

As part of the analysis, the technology of utilizing APG by reinjecting it into the gas cap in order to maintain reservoir pressure has been considered and the potential for its application at oil fields in the Russian Arctic has been assessed.

Gas reinjection increases the pressure in the gas cap and allows to maintain it at the initial level (i.e., initial reservoir pressure – pressure before the development). This, in turn, allows to maintain high pressure drawdown and increase the influx of oil to production wells.

In order to achieve this effect, certain geological conditions are required. Among the key criteria for the applicability of the technology under consideration, the following can be distinguished:

• The presence of a gas cap. A naturally formed gas cap is required due to the existence of risks of loss of injected gas. In the absence of a natural trap, gas can escape into overlying formation;

• Relatively close location of the oil-filled formation to the gas cap. Pressure of the gas cap on the oil-filled formation is possible with the existence of connectivity, which directly depends on the relative location of the formations;

• Homogeneity of the formation structure. The successful implementation of the technology largely depends on the absence of fracturings and highly permeable channels in the rock. In general, the homogeneous properties of the interstitial space of the formation are favorable (such as porosity, permeability, capillary pressure, etc.) due to the fact that the risk of rock destruction during the implementation of the technology for maintaining reservoir pressure under such conditions is low.

The main risk of implementing this method of maintaining reservoir pressure is the gas break-through in oil wells (Table 10). Gas break-through may cause the failure of both downhole equipment and ground-based systems for gathering the production fluid. As was mentioned in the section 1.2 of the Report, the risk of gas breakthrough is associated with a high uncertainty of geology and development modes. The main factors influencing the probability of breakthroughs are the structure of oil and gas reservoirs, the presence of fracturing, reservoir pressure and the mode of development. Since in most

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cases unified gathering systems are used at the fields, its failure may lead to a halt in all production and high repair costs.

Table 10 – Key features and main limitations of the reinjection technology

Technology Mechanism Applicability criteria Risks

Maintaining res- Gas injection into Presence of a gas cap; Gas break-through ervoir pressure the gas cap is ac- in oil wells by reinjecting companied by an in- Close proximity of the APG into the gas crease in pressure oil-filled formation to the cap forcing the oil to the gas cap; producing wells Homogeneity of the formation structure

Source: VYGON Consulting

3.2. Evaluation of the applicability of reinjection technology at the fields of the Russian Arctic Zone

Assessment of the possibility of scaling gas injection technology carried out at all oil fields of the Rus- sian Arctic zone (RAZ). Currently, over 170 oil fields have been discovered in the RAZ, which are at various stages of development. The volume of reserves of dissolved gas and gas-cap gas is 5 tcm (Figure 8). Currently, about 100 fields are under development and about 20 fields will be put into commercial operation next 5 years (hereinafter referred to as considered assets). The remaining fields are at an early stage and their commissioning until 2025 is unlikely.

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Figure 8 – The structure of gas reserves of the oil-and-gas fields in the Russian Arctic Zone, tcm

Source: MNRE, VYGON Consulting

Today, the main oil producing companies in the Arctic zone are Gazprom Neft, Rosneft, Lukoil, No- vatek, etc. Most of the developed oil fields are located in the Yamalo-Nenets Autonomous Region (Fig- ure 9).

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Figure 9 – Major oil producers in the Russian Arctic Zone

Source: MNRE, VYGON Consulting

The current APG production in the Russian Arctic Zone is 28 bcm per annum. This is about 30% of the annual APG production in Russia. Until 2025, it is planned to launch new oil fields, due to which APG production will grow (Figure 10).

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Figure 10 – Forecast of APG production in the Russian Arctic Zone in 2019- 2025

Source: MNRE, VYGON Consulting

The primary criterion for assessing the applica- Basically, it refers to developed fields of No- bility potential of the technology in the oil fields vatek, Gazprom and Artikgaz, mainly located in is the structure of hydrocarbon reserves, specif- the Yamalo-Nenets Autonomous Okrug. At this ically the presence of a gas cap and sub-gas de- stage of the field analysis, 65 assets were ex- posits of oil. Therefore, 10 oil fields of Lukoil, cluded. Gazprom Neft and other companies which do not have gas caps were excluded from further One of the key geological and physical criteria consideration. for the applicability of formation pressure maintenance technology is the distance be- At the same time, fields in the Arctic Zone are tween the oil reservoir and the gas cap, the up- characterized mainly by sub-gas deposits of oil, per boundary of the interval for which is 200 m. however, it is not advisable to consider some According to the distance criterion for the loca- fields as application areas for APG injection tion of the gas cap and the oil reservoir, the ma- technology, namely: jority of the fields are suitable for further consideration. This is due to the specific feature of . fields with a predominantly gas the productive deposits of RAZ. The geological reserves, in which development of oil structure of the northern bench is characterized is not planned in the coming year; by the presence of impermeable sandstones, . fields with a developed gas utilization which became traps for both oil and gas, when infrastructure, where additional hydrocarbons migrated from the parent rock. investments for utilization of Another 30 fields are excluded from considera- associated gas are not required. tion due to the high heterogeneity of the geological and physical properties of the reservoirs,

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the presence of fracture and highly permeable The last step in assessing the applicability of in- channels. Utilization of injection technology on jection technology requires analysis of existing these fields is not recommended due to the high APG utilization schemes in predominantly oil risks of gas breakthrough to oil wells or leakage fields. These are mainly contracts for the gas into overlying formations. supply to the UGSS and to gas processing facilities (Figure 11). At this stage, 11 fields were excluded from further analysis.

Figure 11 – Analysis of current utilization schemes of assets with acceptable geophysical conditions

Source: VYGON Consulting

Thus, the list of target assets (developing fields, • Verkhnepurpeyskoye (RN-Purnefte- as well as fields with the expected launch until gaz, JSC); 2025) to scale the experience of the Novopor- tovskoye field in applying the formation pres- • Tagrinskoe (RussNeft, PJSC); sure maintenance technology by injecting gas into the gas cap is as follows (): • Kholmistoye (Noyabrskneftegaz, JSC); • Severo-Komsomolskoe (SevKom- Neftegaz, JSC); • Pyakyakhinskoye (LUKOIL – West- ern Siberia, JS);

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Figure 12 – Analysis of the applicability of APG injection technology at target assets of the Russian Arctic Zone

-116 121

Others -10

NOVATEK

LUKOIL

Rosneft -65

Gazprom Holding -30 5 -11 Considered fields Lack of natural Mainly NG Highly Commissioned Target fields gas cap production heterogenous APG utilization layers infrastructure

Source: VYGON Consulting

In addition, the current regulatory system in scheme for the utilization of associated petro- Russia involves achieving a target level of APG leum gas at a design stage. For the oil-and-gas utilization of 95%. Therefore, the Companies, industry, the period of the investment stage, takes into account the restrictions on the possi- namely from design to the start of industrial de- bilities of utilization of associated gas at stage velopment, is about 5 years. For 52 fields that of the development of oil fields. On such fields, will be launched after 2025, a decision on the the gas injection technology can be considered utilization of associated petroleum gas can be as additional capacity for APG utilization, taken now. For these fields of Gazprom Neft, which will increase oil production, while main- Lukoil, Novatek and other companies addition- taining the target level of utilization. This ally analyzed the applicability of APG injection mainly concerns the fields of Gazprom Neft, technology (Figure 13). Rosneft, Zarubezhneft, etc. Among the fields for which no investment de- To scale technologies, it is also advisable to cision was made, the main ones, namely 42 as- consider oil fields, for which investment deci- sets, are oil fields. Such fields are excluded sion has not been made and the launch of which from further consideration due to the absence of is unlikely until 2025. One of the limiting fac- a gas cap. Four of the remaining assets are not tors for companies is the administration system suitable for the implementation of injection introduced in Russia in 2009. According to this technology due to the high heterogeneity of system, companies are required to provide an properties across the formations. Thus, it is rec- APG utilization scheme in an oil field develop- ommended to consider the technology of APG ment project. Russian companies provide a injection for five Gazprom groups’ fields and for one field of NovoEnergo (candidate fields).

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Figure 13 – Analysis of the applicability of APG reinjection technology on non-developed assets in the Russian Arctic Zone

-46 52

Others

NOVATEK LUKOIL Rosneft

Gazprom Holding -42 6 -4

Considered fields Lack of natural Highly Candidate fields gas cap heterogeneous layers

Source: VYGON Consulting

ENVIRONMENTAL IMPACT

Of all considered fields of Russian Arctic Zone with commissioning before 2025, only 5 were selected for applying gas injection technology to maintain formation pressure: Severo-Komsomolskoe, Verkh- nepurpeyskoye, Tagrinskoe, Kholmistoye, Pyakyakhinskoye.

Total associated gas production at 5 fields can reach 1.4 bcm in 2025, and the utilization rate will be 95% two years earlier (Figure 14). By 2030 APG production on these assets can reach more than 1.7 bcm.

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Figure 14 – Forecast of APG production, utilization and utilization rate on target assets of RAZ, bcm

Source: VYGON Consulting

At further stages of the analysis and evaluation small ones) and for gas injection (50% of technological effect for all of the listed fields, and 40 % respectively) three scenarios (Table 11, Table 12, Table 13) of APG utilization were considered: • Full-volume injection - the scenario assumes the achievement of the target • Gas utilization program - the scenario level of 95% APG utilization rate, as assumes the achievement of the target well as the reduction of harmful pollu- level of 95% APG utilization rate tant emissions, due to the implementa- through the utilization of gas for own tion of the best available technologies needs: electricity generation, oil heat- in terms of efficiency and environ- ing, etc. mental disposal. The main part of produced APG is transmitted for gas in- • Partial injection - the scenario as- jection (90% for large deposits, 85% sumes the achievement of the target for small ones), except the volumes level of 95% APG utilization rate due required for own needs. This is oil to the utilization of gas both for own heating, boiler houses and other types needs (50% for large fields, 60% for of heat and electricity generation.

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Figure 15 – APG utilization forecast by directions in three use scenarios, bcm

1 600

1 200

800

400

0 1 2 3 1 2 3 1 2 3 1 2 3 1 2 3 1 2 3 1 2 3 2019 2020 2021 2022 2023 2024 2025

1. Gas utilization program Balance-of-plant needs 2. Partial injection 3. Full-volumes injection Injection

Source: VYGON Consulting

Environmental assessment for all mentioned Thus, according to the analysis of the applica- scenarios (Gas utilization program, Partial in- tion of APG reinjection technology for for- jection, Full-volumes injection) takes into ac- mation pressure maintenance on selected assets, count and complies with the following regula- the environmental performance of the imple- tory documents: mentation was confirmed: in the partial injection scenario, the reduction of SLCP emissions • Guidelines provided by the relevant into the atmosphere increased by 5% compared legislation of the Russian Federation with the utilization scenario provided by gas on Environmental Impact Assessment; utilization program. Besides, the implementation of gas reinjection up to 85-90% of pro- • EU Directives codified by Directive duced APG will reduce emissions by another 2011/92 / EU and supplemented by 10%. Figure 16 presents comparison of the Directive 2014/52 / EU, including an SLCP emission reductions effects in different overview of the Environmental Impact scenarios. SLCP included in “Other pollutants” Assessment Directives; group weren’t specified as each of them repre- sents relatively small share of total pollutions. • Environmental, Health and Safety Absolute reduction effects for specific pollu- Guidelines for Offshore Oil and Gas tants are presented in following tables (Table Development by IFC. 11, Table 12, Table 13).

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Figure 16 – Comparison of the emission reductions effects in different scenarios, Mt C02-eq.

+10% 20 2%

5% +5% 18 1%

17 5% 93% 5% Methane 94% Other pollutants 95% Black Carbon Gas utilization program Partial injection Full-volumes injection

Source: VYGON Consulting

Table 11 – Emissions reductions of the major pollutants in the gas utilization program scenario, t

Pollutant 2019 2020 2021 2022 2023 2024 2025

CO2eq., Mt 2.0 2.1 2.0 2.1 2.7 2.9 3.2

Black carbon 2 123 2 254 2 091 2 235 2 800 3 076 3 353

Methane 319 342 316 341 453 493 538

NMVOC 1 385 1 451 1 355 1 432 1 669 1 856 2 016

NO 723 761 709 752 893 991 1 077

NO2 117 124 115 122 145 161 175

SO2 23 25 24 25 30 34 37

H2S 0 0 0 0 0 0 0

CO 309 51 32 857 30 487 32 574 40 726 44 754 48 781

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Pollutant 2019 2020 2021 2022 2023 2024 2025

Benzo(a)pyrene 2.1∙10- 2.2∙10- 2.1∙10- 2.2∙10- 2.8∙10- 3.0∙10- 3.3∙10- 9 9 8 8 8 8 8

Source: VYGON Consulting

Table 12 – Emissions reductions of the major pollutants in the partial injection scenario, t

Pollutant 2019 2020 2021 2022 2023 2024 2025

CO2eq., Mt 2.1 2.3 2.1 2.3 2.8 3.1 3.4

Black carbon 2 240 2 379 2 207 2 359 2 955 3 246 3 538

Methane 942 1 017 938 1 015 1 359 1 477 1 616

NMVOC 1 290 1 352 1 262 1 334 1 555 1 729 1 878

NO 1 246 1 324 1 230 1 314 1 626 1 791 1 953

NO2 202 215 200 214 264 291 317

SO2 21 23 22 23 28 32 35

H2S 0 0 0 0 0 0 0

CO 29406 31 210 28 960 30 938 38 662 42 488 46 309

Benzo(a)pyrene 2.1∙10- 2.2∙10- 2.0∙10- 2.2∙10- 2.7∙10- 3.0∙10- 3.2∙10- 9 9 8 8 8 8 8

Source: VYGON Consulting

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Table 13 – Emissions reductions of the major pollutants in the full-volume injection scenario, t

Pollutant 2019 2020 2021 2022 2023 2024 2025

CO2eq., Mt 2.4 2.6 2.4 2.5 3.2 3.5 3.8

Black carbon 2 498 2 652 2 460 2 630 3 294 3 619 3 945

Methane 1 606 1 726 1 592 1 718 2 288 2 488 2 719

NMVOC 1 589 1 666 1 555 1 644 1 916 2 130 2 314

NO 1 523 1 617 1 501 1 604 1 996 2 196 2 393

NO2 247 263 244 261 324 357 389

SO2 26 28 27 29 34 39 43

H2S 0 0 0 0 0 0 0

CO 33 425 35 477 32 919 35 169 43 955 48 305 52 649

Benzo(a)pyrene 2.2∙10- 2.3∙10- 2.1∙10- 2.3∙10- 2.9∙10- 3.1∙10- 3.4∙10- 9 9 8 8 8 8 8

Source: VYGON Consulting

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4. LIST OF COMPANIES FOR PROVIDING DECISIONS ON ADDITIONAL INVESTMENTS IN PROJECTS AIMED AT SOOT AND METHANE EMISSIONS REDUCTION

Based on the results of fields analysis in terms of APG injection technology applicability, a list of upstream operators (Table 14) is prepared. The operators are planned to be further acquainted with the results of this study. The key goal of acquaintance is decision making on additional investments to reduce soot and methane emissions from APG production in Russian Arctic Zone.

Table 14 – List of companies with target assets and interaction status

Company License holder Asset Status

Rosneft, Equinor SevKomNeftegaz Severo-Komso- Greenfield molskoye OGCF105

Rosneft RN-Purneftegaz Verkhnepurpeyskoye Brownfield OGCF

RussNeft RussNeft Tagrinskoye OGCF Brownfield

Gazprom neft Noyabrskneftegaz Kholmistoye OGCF Brownfield

LUKOIL LUKOIL – Western Pyakyakhinskoye Greenfield Siberia OGCF

Source: VYGON Consulting

All assets from the final list are located in the Yamalo-Nenets Autonomous Region, which today has the highest degree of geological exploration in comparison with other regions of the Russian Arctic Zone and, consequently, a greater concentration of oil fields. For example, the initial assets list (before the identification of geophysical barriers to the injection technology applicability) included 60% of the Yamalo-Nenets assets.

105 Oil and gas condensate field

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Figure 17 – Geography of applicable for injection technology assets

Novoportovskoye

Pyakyakhinskoye

Verkhnepurpeyskoye Severo-Komsomolskoye

Tagrinskoye Kholmistoye

Source: MNRE, VYGON Consulting

bcm of APG. At the same time, gas depletion SEVERO-KOMSOMOLSKOYE FIELD amounted to less than half a percent. Attaining peak levels in extraction is possible after 2025. Severo-Komsomolskoye oil and gas condensate field is located in Nadym and Pur districts of the Severo-Komsomolskoye field can be character- Yamal-Nenets Autonomous Region of the Tyu- ized as a multi layered reservoir. Petroliferous men Province. strata in their geological and physical characteristics have a fairly high spread. This is related Severo-Komsomolskoye field was discovered to the presence of different formation periods in 1969, while commissioning took place only deposits in the structure. The depth of the lay- in 2019. The field is developed by SevKom- ers, characterized by favorable conditions for Neftegaz, 2/1 owned by the Rosneft Oil Com- the implementation of injection technology, av- pany and the Norwegian state-owned energy erages to 1 500 m. Average permeability for this company Equinor, respectively. The implemen- layers is 20 10-3 μm2 (Table 21). tation of the Severo-Komsomolskoye field project development is a part of the cooperation agreements between the companies reached in VERKHNEPURPEYSKOYE FIELD 2013. In 2015–2019 period the parties con- jointly conducted successful pilot operations at Verkhnepurpeyskoye oil and gas condensate the field. Therefore, technical and geological field is located in Pur district of the Yamal-Ne- solutions for the project were clarified, well nets Autonomous Region of the Tyumen prov- drilling technologies were tested, and actual ince. data on extraction and productivity were obtained. Verkhnepurpeyskoye field was discovered in 1976, while commissioning took place only in As of 01.01.2019, remaining recoverable re- 1987. The field is developed by RN-Purnefte- serves, according to the National Reserves gaz, a Rosneft subsidiary that was acquired by Commission, amounted to 201 Mt of oil, 125 the company in 1996.

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As of 01.01.2019, remaining recoverable re- KHOLMISTOYE FIELD serves, according to the National Reserves Commission, amounted to 10 M t of oil, 9 bcm Kholmistoye oil and gas condensate field is lo- of APG. More than 9 mcm of APG were ex- cated in Pur district of the Yamalo-Nenets Au- tracted in 2018. Attaining peak levels in extrac- tonomous Region of the Tyumen province tion is possible after 2025. within the boundaries of the same license area.

Verkhnepurpeyskoye field can be characterized Kholmistoye field was discovered in 1988, as a multi layered reservoir. Layer depth aver- while commissioning took place in 2006. The ages to 2 300 m. Most of the reservoir layers are field is developed by a subsidiary of Gazprom characterized by favorable conditions for the neft. implementation of injection technology due to homogenous properties and average permeabil- As of 01.01.2019, remaining recoverable re- ity of 70 10-3 μm2 (Table 21). serves, according to the National Reserves Commission, amounted to 5 M t of oil, 2.4 bcm of APG. More than 100 mcm of APG were ex- TAGRINSKOYE FIELD tracted in 2018. Attaining future peak levels in 180 mcm extraction is possible by 2024. Tagrinskoye oil and gas condensate field is located mostly in Nizhnevartovsk district of the The geology of the deposit is well explored. Khanty-Mansiysk Autonomous Region and Layer depth averages to 2 700 m. Layer struc- partially in Pur district of the Yamalo-Nenets ture is characterized by favorable conditions for Autonomous Region of the Tyumen province. the implementation of injection technology. Permeability averages to 70 10-3 μm2 (Table Tagrinskoye field was discovered in 1975, 21). while commissioning took place in 1978. Since 1997 the field is developed by Varyeganneft, a subsidiary of RussNeft. Extraction peak levels PYAKYAKHINSKOYE FIELD were attained in late 1980-s, annual oil production exceeded 2 Mtpa of oil. Pyakyakhinskoye oil and gas condensate field is located in Taz district of the Yamalo-Nenets As of 01.01.2019, remaining recoverable re- Autonomous Region of the Tyumen province. serves, according to the National Reserves Commission, amounted to 105 Mt of oil, 29 Pyakyakhinskoye field was discovered in 1989, bcm of APG. More than 1.5 bcm of APG were while commissioning took place in 2016. The extracted in 2018. Attaining future peak levels field is developed by a subsidiary of LUKOIL. in 900 mcm extraction is possible by 2028. In 2009, the first preparatory stage of the field development was completed. In 2014 an active Tagrinskoye field can be characterized as a phase of the field development started and the multi layered reservoir. Petroliferous strata in rate of well drilling increased. Prospecting sur- their geological and physical characteristics veys anticipated plans for the drilling of explo- have a fairly high spread. This is related to the ration wells from 2014-2017. presence of different formation periods deposits in the structure. The depth of the layers, charac- As of 01.01.2019, remaining recoverable re- terized by favorable conditions for the imple- serves, according to the National Reserves mentation of injection technology, averages to Commission, amounted to 45 M t of oil, 16 bcm 1 800 m. Average permeability for this layers is of APG. More than 120 mcm of APG were ex- 20 10-3 μm2 (Table 21). tracted in 2018. Attaining future peak levels in 170 mcm extraction is possible by 2029.

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Prospecting surveys are actively being ex- purpose of maintaining reservoir pressure. tended on the Pyakyakhinskoye field. Layer These include the fields of the Gazprom group depth averages to 3 000 m. Layer structure is (Vaneivisskoye, Yamburgskoye, Lenskoye, characterized by favorable conditions for the Yuzhno-Pireinoye, Beregovoye) and the Yu- implementation of injection technology. Per- zhno-Tanlovskoye field of NovoEnergo. meability averages to 20 10-3 μm2 (Table 21). Assets located in the RAZ, at which the oil production may potentially limited due to the lack OTHER ASSETS of opportunities for APG utilization and at which the prerequisites for the application of There are 6 additional fields located in the RAZ the gas reinjection technology exist, belong to that are not likely to be launched before 2025; Gazprom Neft, Rosneft and Zarubezhneft. however, they have the prerequisites (primarily favorable geological features) for the application of the APG reinjection technology for the

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5. DISSEMINATION OF RESULTS

In accordance with the Terms of Reference, the • necessary measures for the develop- results of Phase 2 will be presented through the ment of state stimulation of APG utili- organization of a seminar for relevant stake- zation holders. • Further steps of the project The key objectives of the seminar are: • Completion (summing up) • Presentation of research results The seminar involves the participation of stake- • Providing a platform for discussing is- holders from both Russia and other countries, sues related to the geological and eco- including: nomic prerequisites for the use of APG reinjection technology for reser- • Representatives of the Project Support voir pressure maintenance purposes Committee

• Strengthening political dialogue with • Representatives of the expert and regulators and authorities ACAP working groups

The seminar will last one day. The preliminary • Ministry of Natural Resources and program of the event includes: Environment of Russia

• Greetings and introduction (NEFCO, • VTB Ecology MNRE, VYGON Consulting) • PJSC “Gazprom Neft” and other Rus- • Presentation of report results sian oil producing companies with as- (VYGON Consulting) sets in Russian Arctic Zone

• Discussion of the following topics at • VYGON Consulting the round table: The seminar will be organized on dates agreed • geological and economic prerequisites by the involved parties after the Final Report. for the use of APG reinjection tech- The location will be selected on the territory of nology for reservoir pressure mainte- the Russian Federation. nance; The seminar will include simultaneous transla- tion into the Russian and English languages.

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6. CONCLUSION

The Novoportovskoye field is unique to the supply of gas to the UGSS, for a number of re- Russian oil and gas industry and, therefore, the mote assets such technologies as mini-LNG applied APG utilization technologies have their plants aimed at the regional market or mini- own unique features. Nevertheless, measures methanol plants that would satisfy the own taken by Gazprom Neft in order to utilize APG needs of the field may become very promising. are considered the best industry practice in the Analysis of the possibility of mass application Russian Arctic Zone. Therefore, it is advisable of BAT-BEPs other than reinjection in the Arc- to scale up the experience of the Novopor- tic requires a detailed study with the involve- tovskoye field and implement it at other north- ment of upstream companies. ern assets. Despite the positive economic effect, the use of technology is limited in the Russian As for the review of the regulatory systems in Arctic due to the geological features of the re- the field of APG utilization and flaring, the gion’s fields. The following key criteria for the analysis revealed that the Russian system for applicability of the technology can be distin- regulating APG flaring is conceptually similar guished, such as presence of a gas cap, close to the system of the province of Alberta since proximity of the oil-filled formation to the gas both set industry-wide restrictions on flaring cap and homogeneity of the formation struc- and set universal regulatory standards in the ture. field of APG flaring for all market participants. This fact suggests that individual decisions and Nevertheless, the potential for reducing emis- mechanisms can be transferred from one system sions from the introduction of APG reinjection to another and implemented in it, without con- technology at the Russian Arctic Zone fields is tradicting the general structure and principles of at least 20 M t of CO2 equivalent, therefore, it regulation. is necessary to work with companies to achieve this potential. A drawback of the current Russian regulatory system is the lack of incentives for further re- At the same time, in order to make a final deci- duction in APG flaring after reaching the target sion on the implementation of this technology APG utilization rate of 95%. In this regard, at the fields considered in the scope of work, it based on the experience of Alberta, it can be is necessary to conduct a detailed analysis of the supplemented by a mechanism for providing in- applicability of the reinjection technology in centives for APG utilization projects that would each individual case. Furthermore, given the otherwise be economically ineffective. The limited use of the reinjection technology benefit may be provided in order to incentivize (mainly for geological reasons), it is advisable faster implementation of the utilization project, to further analyze the applicability of other for example, for new fields. The royalty exemp- BAT-BEPs. In addition to the relatively con- tion, applied in Alberta as an incentive measure, ventional technologies of power generation and in the case of Russia can be replaced with a reduction in MET on oil.

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APPENDIX A. CALCULATION OF ECONOMIC EFFICIENCY OF APG INJECTION

As a step of technology implementation analysis, it is necessary to assess the economic benefits of additional oil production over considered period, taking into account additional capital investments related to APG injection system. For economic evaluation, NPV is used as a key performance indicator.

Net present value (NPV) - accumulated discounted cash flow for the accounting period.

Discounted cash flow is the amount of profit from sales and depreciation deductions reduced by the amount of investments allocated for the injection technology implementation, discounted to the base year. To claim effectiveness of the project, the NPV must be positive; when comparing alternative projects, preference is given to a project with a higher NPV value.

Initial data necessary for calculating net sales as well as gas injection and oil production expenses is presented in , Table 1, Table 19.

OPEX and CAPEX are used in the following calculations represent operating expenses on gas injection and oil extraction, as well as capital expenditures on the required facilities construction.

The Mineral Extraction Tax is calculated in accordance with the Tax Code of the Russian Federation.

The Property Tax rate is set at 2% and is applicable for all property and equipment of implemented project (accumulated and depreciated CAPEX is used for the Tax estimation purposes). The Income Tax rate is set at 20 percent, according to Russian legislation. Income (profit before tax) is recognized as net sales, reduced by the amount of expenses incurred.

𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑡𝑡𝑡𝑡𝑡𝑡 =𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇 𝑇𝑇𝑇𝑇 𝑇𝑇 𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖 ∗ 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑇𝑇𝑇𝑇𝑇𝑇 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅

𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇 𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖=𝑖𝑖 𝑖𝑖 𝑁𝑁𝑁𝑁𝑁𝑁 𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠 − 𝑂𝑂𝑂𝑂𝑂𝑂𝑂𝑂 − 𝑀𝑀 𝑀𝑀𝑀𝑀 − 𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 𝑡𝑡𝑡𝑡𝑡𝑡 − 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷

𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼 𝑡𝑡𝑡𝑡𝑡𝑡 = 𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇 𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖 ∗ 𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼 𝑡𝑡 𝑡𝑡𝑡𝑡 𝑟𝑟𝑟𝑟𝑟𝑟𝑟𝑟

Economies𝑁𝑁𝑁𝑁𝑁𝑁 𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖𝑖 𝑖𝑖on flaring𝑇𝑇𝑇𝑇𝑇𝑇𝑇𝑇 fees𝑇𝑇𝑇𝑇𝑇𝑇 𝑖𝑖𝑖𝑖𝑖𝑖are𝑖𝑖 being𝑖𝑖𝑖𝑖 − considered𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼𝐼 𝑡𝑡𝑡𝑡𝑡𝑡 in cash flow calculations. The economies are derived by subtraction of environmental payments from base case scenario (no utilization, 100% of APG are flared).

Based on these conditional data and taking into account the amount of additional oil production, all free cash flows (FCF) are calculated by years of the investment project under consideration.

= + +

The𝐹𝐹𝐹𝐹𝐹𝐹 discount𝑁𝑁𝑁𝑁𝑁𝑁 𝑖𝑖𝑖𝑖𝑖𝑖 factor𝑖𝑖𝑖𝑖𝑖𝑖 (“r”𝐷𝐷 in𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷 the following− 𝐶𝐶NPV𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶 formula)𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸 that is used𝑜𝑜𝑜𝑜 𝑓𝑓for𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓 cash𝑓𝑓 flow𝑓𝑓𝑓𝑓𝑓𝑓𝑓𝑓 discounting is calculated with open-source data as a cost of equity for Gazprom Neft.

The economic performance indicator (in breakdown with factors) of this investment project is presented in Figure 4, and the cash flows profiles for the period considered in the project is presented in Figure 18.

79 | MITIGATION OF SHORT-LIVED CLIMATE POLLUTANTS FROM APG-FLARING

Figure 18 – Free cash flow related to APG injection technology implementation, M EUR

400

200

-200

-400

-600 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

Source: VYGON Consulting

= 𝑛𝑛 (1 + ) 𝐹𝐹𝐹𝐹𝐹𝐹𝑖𝑖 𝑁𝑁𝑁𝑁𝑁𝑁 � 𝑖𝑖 𝑖𝑖=0 𝑟𝑟 According to the results of calculations, it was found that NPV for the evaluation period is 2.65 B RUB, and given the fact that additional oil production from this technical solution will be observed longer, than the period used in the calculation, this investment project can be considered as an effective.

Analysis demonstrated that the largest segments in abatement cost structure are injection technology CAPEX and Taxes. Taxes segment mostly consists of the mineral extraction tax and excess-profits tax (the second is applicable to a specific list of oil fields, especially in the Arctic). OPEX is much smaller as most is related to oil extraction and increase in production volumes doesn't require additional operating wells and equipment. In addition, economies on environmental fees are relatively small as injection technology is compared with flaring that is considered as BAT-BET flaring (almost soot-free) in the case of Novoportovskoye.

Based on the sensitivity analysis, the maximum sensitivity to oil price was revealed. Even 5% increase in oil price may lead to the project efficiency growth by more than two times. On the other hand, the second largest factor is oil production effect. Worth to mention, that NPV of the project is more sensitive to decrease in oil production than to increase, as economy on taxes cannot reimburse falling revenue.

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APPENDIX B. DETAILS AND SUMMARY ON VARIOUS APG

UTILIZATION TECHNOLOGIES

Within this section a short list of technologies that are the most applicable for utilization of Novopor- tovskoye field APG is formed. The APG volume to be utilized is very large. Taking into account that Yamal Peninsula is remote region with difficult climate conditions, limited access to markets and lack of infrastructure there are heavy constraints to develop new facilities. Basic constraints analysis shows the following:

Table 15 – Constraints for technologies applicability on Novoportovskoye field

Constraint Description Technology made inapplicable

Infrastructure In the area near Novoportovskoye field the only - infrastructure facility is available – oil loading terminal Arctic Gate.

Development of any export-oriented as well as domestic market-oriented production assumes construction of infrastructure that could rise investments by 20-30%.

Scale All the considered technologies are applicable for - APG volumes.

Regional market oriented products could be only small-scaled because of limits in demand

Even export-oriented methanol couldn’t consume more than 2 bcm of gas in accordance with international practice of methanol projects

Regulation The only regulatory constraints is inability to ex- - port gas and LNG. Domestic gas market is regulated by government. Core market price for this products will be YaNAO regional market

Technical There are no free processing capacities in the re- Pipeline to GPP gion of Novoportovskoye field APG Flaring

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All APG flaring on Novoportovskoye field is soot- free and technologies of flaring are not relevant

Geological It is possible to inject gas to gas cap, but risks of - gas breakthrough induces company to have an alternative variants

Structural There no structural barriers for considered tech- - nologies ( e.g. ownership of assets, contracts)

Source: VYGON Consulting

Except barriers, that make technologies inapplicable, there are conditions which make the technology particularly attractive or unattractive.

Fundamental factor influencing technological choice is accessibility to markets and demand on products. YaNAO market is tiny for all products. Thus, all regional market oriented production couldn’t consume products more than 1 bcm in gas equivalent.

The situation on considering product markets is as follows:

Table 16 – Constraints for technologies applicability on Novoportovskoye field

Pipeline gas Gas prices are regulated. APG has priority access to gas transporting system. Independent gas producers have regulatory advantages on domestic market.

Gas of Novoportovskoye field doesn’t have access to gas transport infrastructure. The closest point of UGSS is CS “Yamburgskaya” situated across from Novoportovskoye field through Gulf of Ob.

CNG/LNG Potential demand on CNG on Novoportovskoye field region doesn’t exceed 300-400 MMCM/y and too small comparing to volumes to be utilized.

Potential of deliveries to other regions is absent due to great distances. Export is not allowed by regulation

Oil products Russian gasoline and diesel market is loose. There some risks connected to tax maneuver.

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Methanol and Potential demand on CNG on Novoportovskoye field region doesn’t ex- ammonia ceed 300-400 MMCM/y and too small comparing to volumes to be utilized.

It is a traditionally export-oriented product in Russia

Power Potential demand on heat and power energy doesn’t exceed 300-400 MMCM/y in natural gas equivalent

Source: VYGON Consulting

The above analysis shows that small scale CNG and LNG capacities are not perspective in YaNAO.

At the moment all APG flaring on Novoportovskoye field is soot-free. Due to this power generation technology will have negative effect comparing to base case (soot-free flaring). Thus, the technology is also removed from short list.

Thus, the short list of emission reduction technologies looks as follows:

Table 17 – Technologies summary

Long-list Non-market con- Market constraints Short list straints

Pipeline to GPP Technical

CNG Limited market

LNG Limited market

Power Technical

Flaring Technical

Injection

Methanol

Ammonia

Gas marketing

GTL

Source: VYGON Consulting

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BAT-BEP that are technically applicable for implementation were evaluated in terms of their abatement potential and costs required to gain the potential. Summary of the analysis is presented below (Figure 19, Figure 3).

Figure 19– Comparison of various technologies efficiency for Novoportovskoye field

Abatement cost, EUR/t CO2-eq. 20

10 Ammonia LNG Methanol

GTL 0 CNG Injection 0.0 0.5 1.0 1.5 2.0 NG Pipeline 2.5

Abatement, mln t CO2-eq.

-10

Source: VYGON Consulting

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APPENDIX C. COMPARISON OF APG UTILIZATION TECH- NOLOGIES BY THEIR ENVIRONMENTAL AND ECONOMIC EFFICIENCY FOR THE NOVOPORTOVSKOYE FIELD

Table 18 – Comparison of the total reduction in pollutant emissions by 2025 and related technology costs106

Technology Emission reduction, Emission reduction costs,EUR

per t CO2-equivalent M t of CO2-equivalent

Min. Max. Min. Max

LNG -0.25 -0.05 7.1 9.3

CNG 0.1 0.25 -0.9 -0.4

Ammonia 1.3 1.7 9.8 10.7

Methanol 1.4 1.6 8.0 8.9

GTL 1.6 2.1 -3.1 -0.9

Reinjection 2.1 2.4 -0.9 0.9

Gas pipeline 2 2.5 -1.8 -0.9

Specified reinjection 2.5 -21,7

Source: Carbon Limits, VYGON Consulting

106 Emission reduction costs were estimated as the sum of all cash flows associated with the implementation of the APG utilization project

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APPENDIX D. MACROECONOMIC SCENARIO

Table 19 – Macroeconomic assumptions for evaluating the effectiveness of APG injection technology at the Novoportovskoye field

Parameter Unit 2018 2019 2020 2021 2023 2024 2025

Urals price $/bbl 70 64 60 49 49 49 49

Exchange rub./$ 63 65 63 67 67 67 67 rate

Discount % 14 14 14 14 14 14 14 rate

Source: VYGON Consulting (Macroeconomic assumptions)

All figures in EUR were presented according to the RUB/EUR exchange rate based on Central Bank of Russia information for 2019, i.e. 72.54.

APPENDIX E . EMISSIONS FACTORS FOR APG UTILIZATION UNITS

Table 20 – Pollutant emissions factors for APG utilization units

Sources of pollutant Pollutant emission emissions Methane NMVOC NOx CO

t/ mln cubic Wt % t/ mln cubic t/ mln cubic m CH4 m CH4 m CH4

Gas processing plant 0.100 0.0 - - (min)

Gas processing plant 0.105 0.4 - - (max)

Stream ejector 0.001 - 0.500 3.175

Gas turbine booster / 0.001 - 0.600 3.810 compressor package

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Sources of pollutant Pollutant emission emissions Methane NMVOC NOx CO

t/ mln cubic Wt % t/ mln cubic t/ mln cubic m CH4 m CH4 m CH4

Boiler /oil heating unit 7.348 - 3.340 7.331

Gas-turbine electric 0.050 - 1.494 0.882 power plant

Gas engine electric 6.250 - 3.010 6.600 power plant

Injection pump and 0.010 0.035 valves

Source: Vygon Consulting analysis

APPENDIX F. GEOPHYSICAL PROPERTIES OF TARGET AS- SETS

Table 21 – Geophysical properties of target fields oil layers

Field Layers Terrigenous / Homogeneity Average Average quan- carbonate ba- depth of oil permea- tity sin layers, km bility, 10-3 μm2

Severo-Komso- 67 67/0 Homogenous 1.4 20 molskoye properties layers exist

Verkhnepur- 39 39/0 Homogenous 2.3 70 peyskoye properties layers exist

Tagrinskoye 120 120/0 Homogenous 1.8 20 properties layers exist

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Field Layers Terrigenous / Homogeneity Average Average quan- carbonate ba- depth of oil permea- tity sin layers, km bility, 10-3 μm2

Kholmistoye 5 5/0 All layers have 2.7 70 homogenous properties

Pyakyakhinsko 16 16/0 All layers have 3.0 20 ye homogenous properties

Source: MNRE, VYGON Consulting

APPENDIX G. BASELINE EMISSIONS LEVEL

Table 22 – Emissions of the major pollutants in the baseline scenario, t

Pollutant 2019 2020 2021 2022 2023 2024 2025

CO2eq., Mt 2.4 2.6 2.4 2.5 3.2 3.5 3.8

Black carbon 2498 2652 2460 2630 3294 3619 3945

Methane 1721 1848 1704 1839 2446 2660 2907

NMVOC 1589 1666 1555 1644 1916 2130 2314

NO 1941 2062 1913 2044 2561 2813 3066

NO2 315 335 311 332 416 457 498

SO2 26 28 27 29 34 39 43

H2S 0 0 0 0 0 0 0

CO 35 798 38 015 35 266 37 693 47 218 51 868 56 541

Benzo(a)pyrene 2.2E-8 2.3E-8 2.1E-8 2.3E-8 2.9E-8 3.1E-8 3.4E-8

Source: VYGON Consulting

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